Grant King – Managing Director
Karen Moses – Executive Director, Finance and strategy
Frank Calabria – CEO of Energy Markets Business
David Baldwin – CEO of LNG Business
Paul Zealand – CEO of Upstream Business
Jason Steed – JPMorgan
Mark Samter – Credit Suisse
Dale Koenders – Citigroup
John Hirjee – Deutsche Bank
Ian Myles – Macquarie Equities
Simon Chan – Bank of America Merrill Lynch
Origin Energy Ltd. (OTC:OGFGF) Q4 2014 Earnings Conference Call August 20, 2014 8:00 PM ET
Hi, good morning all, and welcome to our 2014 results presentation. This year we're trying something a little bit different in that this year, for the first time, there's no visitors in the room. We're doing it entirely on broadcast. And I hope this work for you all. Many of you suggested we should move to this format. And hopefully we can still have a good discussion and answer all of your questions in respect to the results, and we'll be looking forward to any feedback you might want to give us as to how well this format's worked.
So with that explanation, we'll go underway, and again welcome. If I could introduce my colleagues who'll help me, particularly in the Q&A session and the presentation, to my -- moving immediately to might right, our Executive Director, Finance and Strategy, Karen Moses; CEO of our Energy Markets Business, Frank Calabria; CEO of our LNG Business, David Baldwin; of our Upstream Business, Paul Zealand; Andrew Clarke, our Company Secretary and General Counsel; Carl McCamish looking after all of our people and culture; and Phil Craig looking after all of our public and government affairs and communications.
So again, welcome all, and hopefully through this presentation and by question-and-answer we can help you understand what's happened in Origin in the last year and what the future we think will look like.
So if we turn to the presentation, and we'll go straight into -- sorry, just moving through how we'll it up. I will give you some introductory comments on our overall performance, what I think the key things are. Karen will take you through in some detail our underlying financial performance. And then I'll come back and take you through a review of operations, and perhaps more so than we have in the past, talk a bit about our prospects for the future, how we think the future plays out.
So if we go firstly to the highlights, obviously the statutory profit, as you can see, is up 40%. Karen will touch on that a little bit, and there's plenty of explanation of that variance in our OFR, so I won't dwell on that.
Our underlying profit down 6%. You'll find through the course of the presentation that that's more than entirely accounted for by the effects on our sales volumes of historically mild weather we've had this year, I think a theme that all of us in the energy business are reporting on. And the additional provisioning we made as we exited some of our existing activities, particularly in Africa, in Kenya and South Africa, as we've focused our exploration efforts here in Australia and New Zealand regions. You'll find those two things account entirely for that difference.
I think very pleasingly, the Group cash flow of over $2 billion shows the underlying operational performance of the business, and of course it's been very strong.
In terms of the two measures that we hold above all others, for the first time in three years our total shareholder returns exceeded market. We acknowledge for the last two years that's not been the case. And we're hopeful that as we get closer and closer to APLNG coming online with the CLNG project, we can convince investors of the true value we believe exists in our business.
And of course it's very important to us that whatever we do, we can do safely. And very pleasing to see a very significant improvement in our safety performance where our TRIF is down to 5 from 6.5 in the prior year.
So overall, profits down a bit; we can explain why that's happening. Cash flow, very, very strong. And obviously from a point of view of returns and safety, we think a much more positive year for the company.
If we start to look in just a little bit more detail why is that underlying profit down. It's down primarily because of lower results in energy market segments, all other segments contributor higher result. And the energy market is down primarily due to variances around sales volumes, which again we'll talk to in more detail later in the presentation. And of course part of that, not all of it, but part of that is weather-related. A very strong contribution from upstream business, in a sense held back just a little bit by a significantly higher level of exploration provisioning contribution from Contact.
That underlying operational performance has resulted, as I said, in a very strong increase in cash flow. Part of that is catching up from the prior year; part of that is reflecting, as I said, the strong operational performance in the business. That catch-up in the prior year of course been around, that is where we had a poor result in the prior year.
And I think very importantly, APLNG remains on track for first LNG production in mid-2015. And quite coincidental in timing, but as of Friday, the approval of the EBA by unions on Curtis Island in our view removes one of the significant risks remaining, which has been ahead of us for some time, that is the renegotiation of that EBA. So the risk in our view continue to diminish around delivery of that project.
Now because of that strong underlying operational performance and, excuse me, the strong cash generation and the very good progress made by APLNG, we've decided to fund the acquisition of the Browse exploration interest which we announced in late, from memory, or early June. At that time we said we would raise up to $1 billion of equity to fund that acquisition. It is now our intention to fund that acquisition by hybrid, through a hybrid issuance, a European hybrid issuance, not an Australian hybrid issuance. That market appears to us to be strong; it will open again shortly, I believe, Karen, and we believe it's quite appropriate for the company to access the additional fundings through that market, which of course using a hybrid will also bring some of the equity credit that we will need to maintain our investment grade credit rating.
So we've made a clear decision. As you know, that transaction is completed, it is actually paid for through our existing debt facilities. But we'll replace that debt with the issuance of a European hybrid; that is our intention.
Over the last two or three years we've worked to a pretty clear set of priorities. Clearly those two or three years have seen energy markets businesses particularly in Australia, a little bit earlier in New Zealand, struggle through increased competition and excess supply. And we've worked very hard to improve the operational performance of those businesses, and we've, as you can see, tick many of the key areas that we were working on. I won't read them through in all detail, but hopefully through the presentation you'll see that we've progressed in all of those areas.
As I said, APLNG is continuing to deliver on the LNG project and progress there is very good. And of course, we have been able to fund the business and its activities again by virtue of the announcement to go to the European hybrid market without raising equity, and it's our intention to do so as we move through to the point where APLNG begins to deliver the cash flow and earnings as that project comes online.
We continue to have an eye on the future in creating opportunities, and many of those have been progressed for example without a lot of exploration opportunities into the overall portfolio, and also some renewable opportunities.
But I think the key feature for us is that, as we look to the future, we are clearly entering a couple of years of transition. These will be two transitional years for Origin. APLNG, we are very confident, will deliver first LNG in mid-2015, first production of LNG in mid-2015. And the energy markets businesses are maturing. And therefore it's time to refocus our priorities as we look to those next two to three years.
Clearly we'll focus on now improving returns in the energy markets businesses. There was quite a number of operational issues we needed to work on, particularly as we went through implementation of these systems and completed investments and integrated acquisitions. That is now behind us. It's time to really work on improving returns in those businesses.
We do now need to deliver the growth that we've been talking about in our gas businesses, clearly primarily through APLNG, but there's a lot of opportunities to grow our existing upstream operations. And in broad terms, for strategic reasons, as you know, gas is good, and gas is good in Australia, we can connect it to domestic and export markets. We're very determined to deliver the growth that we can do through that focus.
And we do want to continue to build our position in renewables, and we'll talk a little bit about renewables because the thing that distinguishes us is really a focus on renewables in a world that doesn't require subsidies. And clearly through our investment in Contact in New Zealand, but through a portfolio of opportunities, particularly in countries like Chile [ph] and Indonesia, we do see significant opportunities to grow our investments in renewables.
And all of that needs to be done mindful that over this transitional period we do need to increase distributions to shareholders. We intend to do that. And we'll talk a little bit about that again through the presentation. We do need to maintain our investment grade credit rating. And to the extent that we can prioritize those increase in distributions and maintaining that investment grade credit rating, we do also need to keep an eye on growth and recycle some of the cash generation in the business into our growing businesses which we talked about particularly in natural gas and renewables.
Now with those introductory comments, I'd like to hand over to Karen. And Karen will take you through the financial results, and then I'll come back and take you through some of the highlights of operational performance. Thanks, Karen.
Thanks, Grant. Morning everybody.
So just to turn to the financial highlights page, just to bring out some of the key numbers. If I could have the page turned, that would be great. Thank you. Okay.
So from a statutory profit perspective, up $152 million, and I will come back to explain the movements both between the statutory profit and the underlying and year-on-year itself.
Looking at the EBITDA performance, 2% reduction or $42 million, and then 6% EBITDA level, with some of that EBITDA increase coming with additional depreciation as well.
Interest cost positively moving for the year, and a little bit of capitalized interest shift and lower interest cost as well. So, both fronts sharing in that improvement.
Grant reflected on the strong cash flow for the year, and $2 billion OCAT, clearly a very strong year. Difference between free cash flow and OCAT simply really reflecting the old monetization that we did in the prior year that isn't reflected in either of the OCAT numbers.
Capital expenditure controlled on the year, so stay-in-business and growth CapEx around $1 billion, with a very significant contribution to APLNG of over $3.8 billion, which is David will reflect on just how progress that reflects for the project as well.
And finished the year really with the same uncommitted facilities, with a significant amount of refunding that we did through the year.
So just looking at EBITDA, the major drivers is energy markets down $280 million. About $200 million of that is the lower volumes, the warmer weather, energy efficiency, and Grant and Frank will reflect on that.
We had a year where we had a different movement in provisions relative to the cash cost of serving the energy markets business, and that probably is the other -- the major contributor to the lower energy markets business, just that move on year on year in line with [ph] the TSA.
A stellar year for E&P. Higher production and higher commodity prices both contributed to that stronger EBITDA result, and of course that's also carrying the additional exploration write-off that we did through the year, which you'll see in kind of two places. Botswana [indiscernible] JV. Equity accounting and exploration expense reflect the -- reflects the other changes.
Contact is reflecting both benefits of the exchange rate movement, and you'll see that both in the asset base and in earnings. And depreciation and amortization up really for the additional production that we're seeing, as we've already reflected. And some movements in the other businesses.
So, statutory profit to underlying profit, slight change in how we would -- you'd normally see this. Asset disposals, dilutions, impairments have now all been aggregated, really reflecting a similar activity. But the decrease in fair value of instruments is essentially commodity prices, including electricity, and particularly, if you recall, the caps don't get to be effective hedges, so electricity caps flow through that line, and also reflecting the lower wholesale prices that have been evidenced through the year.
The asset disposals, we benefited from the restructure that we did around GenTrader arrangements and the Cobbora Supply agreement. With some impairments, PNG we talked about at the first half, with changes in relationships around the asset in New Guinea, some additional impairments. Probably the one that is slightly different in this is what we did have a long-term contract where we prepaid [ph] for some carbon, and with the repeal of the carbon, we've now impaired that asset, and that's probably about half of the other asset disposals and impairments and some -- just some maturing assets in the upstream as well.
LNG related items, just very straightforward, simply the financing cost that's attached to that, and that's consistently with how we've been reporting that asset on -- as an equivalent to as if we had owned the asset ourselves, we would have been capitalizing that interest. And APLNG carries some of the foreign currency movements attached to some of the funding.
There's also some pre-production costs appearing in that line, which is again essentially capital costs that would -- don't relate to the underlying performance of the domestic businesses, which is what we want you to see when you look at the APLNG performance line.
Retail Transformation at the first half had $43 million of transformation and stabilization costs. That's $16 million -- another $16 million has come through the second half, bringing that sort of New South Wales activity to an end. And again we talked at the first half about the potential change about the unbilled income, and that of course was concluded through the year as well.
So that's the -- if we think about the business, we encourage you of course always to look at the underlying profit, but very transparent in how we have reflected that.
If I moved to the OCAT line -- the OCAT slide. We've talked about most of the items on here, but very strong working capital of $461 million, you can see in the second line. It almost is entirely energy markets improved performance, and a little bit of working capital improvements in the upstream as well. From an exploration expense, you can see that reflected there, and we already had discussed that.
The step-up, sorry, I should have just paused, the step-up in stay-in-business CapEx is actually just a timing reflection for the energy market business. It's not a fundamental shift in what we would expect to be seeing in that area.
The TSA, you can see that big movement year on year, but both the TSA and the hedge contracts, provision for the hedge contracts that we've always brought back through that line. So, much more of the EBITDA is now reflecting in cash, which is what we said would be the highlight of that change.
And tax is simply a timing issue. It was highlighted last year as one of the changes in the year, and that's come back this year as we always have those sort of timing changes. So, nothing in there.
The result of both of that strong cash position and a smaller movement in productive capital of course is a substantial increase now in our OCAT ratios from 6.4% to 11.5%. So, pleasing to see.
The segment returns, you can see the, despite the lower result, that the strong cash result for energy market we can see the strong step-up in, both the OCFR for energy markets and exploration and production, and Contact has had a pretty stable year, and again the movements are essentially reflecting ForEx in that.
The capital slide, growth capital expenditure slide just highlights just how much of our free cash flow is being invested in APLNG and how much controlled capital has been put against the balance of the business.
Grant already reflected on our funding and our intentions around the Browse acquisition. Of course it has concluded and undrawn facilities were used to fund that initial payment. And we will be going to the hybrid market.
It's been -- I reflected on this fact this morning, and for the amount of funding we've done this year, we've actually been pretty silent on it, but here all the way, of how much funding we've just done this year when we stood here a year ago having just announced the complete refinancing of our debt book. Of course we went to Europe and we went to the U.S. to replace and lengthen some of those facilities. And that's reflected in that maturity profile.
And from a dividend perspective, this slide looks slightly different to what we would normally show. We would normally just show you the dividends, and you can see that dividend has been maintained at $0.50 a year, which is the higher of the 60% payout ratio at 77%.
As you can see with the free cash flow, of course a lot of that additional cash is -- or all of that additional cash has been used to support APLNG and the investments in the business. And you can see we're stepping into a transitional period where APLNG will start substantially increasing the free cash flow that's available. And of course the draw on capital for the business will be reducing, so we're now at the point where we can start better describing and giving more shape to how we might be thinking about the future in that regard.
And I'll change back to Grant for the operational review. Thank you.
Thanks. Thanks, Karen. So we'll now go through each of the businesses and call out what I think are some of the key things to talk about, then a little bit about prospects and outlook, and then on to questions and answers.
So if we turn firstly to the energy markets business, as we've clearly covered EBITDA down, a couple of percent good increase in cash flow. Again a lot of that recovering a bit from the prior year where our debt is, in particular our billing fell a bit behind, but also indicative of just good performance, certainly operationally across the business. And visually this point reinforces the point Karen made in respect of growth CapEx, that there's very little capital, certainly growth capital, going to these businesses and stay-in-business CapEx is reasonably constant now across the years in these businesses as well.
I won't talk to each of the points on this page because we'll talk to them in respect of subsequent slides. And firstly, in respect of what's driving that result. As you can see, it's all coming out of the electricity segment and out of operating costs. So on the face of it, contribution from electricity down $183 million and higher cost of $67 million being the two primary drivers.
Just I won't talk about it further in the presentation, but in respect of what that LPG and non-commodity segment, that's effectively less solar installations as subsidies are withdrawn, and a slightly lower contribution from our LPG business. But primarily it's a story about volume in the electricity business and cost.
So if we then go to the electricity business and show you what's happening or what has happened, this chart to me captures all of the key issues. Firstly, the industry does continue to price at what we call a rack rate or a headline level on a sensible basis. The industry is tending to price either through pricing outcomes where they still exist. In case of New South Wales, the pricing agreement we reached with the government is -- price controls were withdrawn, and Victoria and South Australia, what industry sets its prices, price outcomes are generally okay.
But you can see the discounting is continuing a little bit. And the sort of net effect, if you like, of discounts is to move from 2.4% to 3.7% of revenue.
In a sense, the magnitude of discounts which people talk a lot about, don't worry about too much, because you need to look at whether prices are going up, because the discounts were of course off the rack rates. And so overall, our unit revenue or revenue on a unit sales basis dollars per megawatt-hour is up $6.9 a megawatt-hour. And you can see there our total cost of goods sold is up 7.9. And that's why there's been a $1 of margin compression in the business on a dollars per megawatt basis.
Now some of you might recall that at the half-year that was $3.20, and therefore clearly in the second half we're seeing a substantial change in circumstance, and you'll find that's the story about much of the things in our energy markets business that I believe in the second half we've, if you like, come off the lowest point which was our first half, and we're seeing better outcomes in nearly all areas of the business.
So overall that margin compression across our energy -- or electricity segment for the year is only about 3%. That is $1 a megawatt-hour. But our gross profit per customer is down 11%. And that's essentially entirely driven by volume, that is lower sales per customer, and we'll look a little bit at what's contributing to that in a minute. So effectively the story of the year and the driver of that major variance in all of Origin, in the energy markets business, in the electricity segment, is volume, volume per customer. That is in part driven by the, as I said, the historically warm winter we had and also in part for other trends that are reducing average consumption per customer.
So overall, the second half in our view was very strong. Our cost of energy was down relative to first half, if you like, management of discounts was far better. So whilst overall discount increased, [indiscernible] rack rates go up net of discounts, there's not actually that much margin compression in business as it plays out for the full year, clearly a strong second half.
If we look then at those things firstly impacting volume, clearly there has been a trend of a falling volume per customer in the year just reported, the FY14 year, clearly exacerbated by the mild winter, which all of us -- and I have to say both ends of the winter -- July/August last year and May/June this year, which all of us in the industry have commented on. And that's probably about a quarter to a third of that volume variance.
It is expected that the rate of decline, if you like, in average consumption will fall. But it's also fair to say that a lot of that was through -- or the key drivers of that is the take-up of solar and the impacts of energy efficiency and change in consumer behavior reflecting higher prices.
Now, prices have really stabilized. There's not now the headline increases in electricity prices, certainly some in gas but not in electricity now so much compared to prior years. And we note there that that large increase in solar installation was driven by $6 billion of subsidies over those three years of 2011 to 2013, much of which have now been withdrawn. There are still some. And that's reflected in much lower rate of growth of solar PV installation. So we do expect the rate of degradation, if you like, of that average consumption to decline, and we'll talk a bit more about what we think the future looks like when we talk about prospects later on.
So that's the volume story in the electricity segment. In terms of discounting, there was, if we look across all markets across the second half, in fact there was a bit of an increase. We were hoping to see a slight reduction in discount in New South Wales. There was a bit of an increase with more tier 2 activity, mainly driven by generator-backed retails in New South Wales. And certainly in Victoria, which is the market with the highest margins, and not therefore surprising, where there's been most competition around discounts, but of course, off a higher rack rate, off a higher price.
But we're again seeing, post June 30, some moderation in those trends, but of course it will be as it will be. But certainly from Origin's perspective, we're trying very hard to manage discounts in order to maintain that mix of market share versus discounting.
If we look at the cost of energy, we explained in the first half that our cost of energy was higher than benchmark for a couple of reasons. One was the significant use of own generation. And the other was hedge positions that we hold, particularly coming through the prior year in Queensland.
Clearly in the second half our cost of goods sold if you like, that wholesale cost of energy across the whole portfolio, that is what comes from our generation and what comes from our book, improved. So overall we're probably tracked across the year at a bit below benchmark, and we think the appropriate benchmark is contract price, such the one you forward-price, because that's the price that the big retailers essentially pay for their hedge position.
So we think our cost of goods sold are tracking in line with benchmark and now maybe a little bit better than benchmark. Across the year, as you can see, we did generate a higher proportion of our own energy, and that's because there is plenty of gas in the market, so we've been able to drive that gas generation hard. And that price of that gas, surprisingly, in the spot market is quite low, because as we entered the ramp phase for the LNG industry in Queensland, there is clearly gas available on often an intermittent basis, that is a non-firm basis, that Origin is able to take advantage of.
An important point to note there is that, in 2014 we put 55 petajoules of gas into power generation. As we go into 2015 and 2016, FY15 and FY16, that gas will rotate into LNG a fair amount of that gas, and we've talked previously about the sort of margin expansion that occurs when that happens. And that will contribute to an increase in energy market results over the next two years in particular.
So, cost of goods sold, if you like, the wholesale cost of energy and our own cost, that is the portfolio of cost of energy, much better in the second half, contributing again to that lessening of margin compression to the point where again the key story in electricity is all about volume.
In natural gas, the same story. You can see there, as we've been contending, that we can see very significant margin expansion. So unit gross profit dollars per gigajoule sold up 19%, as the benefit of Origin's legacy position in gas comes through, and we see higher prices for gas.
But the gross profit per customer was down 4%. And again there are two primary reasons for that, both volume related. The first is of course weather, and weather in a sense has a greater relative impact in gas because gas is a heating business, particularly in Victoria and New South Wales. So again, good expansion in unit margins, but a reduction, in this case not even a lower number, but a reduction in gross contribution per customer because of that volume effect.
That has been exacerbated a little bit by what we call a true-up. There is a process in the industry where our sales -- we measure our sales of what we pay for or buy from producers and from the distributors, they tell us what we've bought. That process has a true-up, and unfortunately this is a year where that true-up has had an impact on that number as well and we've had to effectively back out a bit on margin I think, Frank, against that true-up process. But that's just a one-off true-up, and with our new systems, we do not expect that to occur going forward. So, primarily again a volume-driven effect in the gas business.
In terms of customers and churn, net customer position was a loss of 3,000 customers, so, effectively we've held our customer position. But there was a bit of rotation in that, 38,000 more in gas, 41,000 electricity. And we've talked about that rotation quite a bit over the last year or two. Clearly gas is a strong position, so we're happy to make up some of that competitive effect in electricity markets, in a sense slightly prioritize margin knowing we'll lose a few customers, but we're picking up those customers in gas.
Now historically, and even in FY14, that rotation sees a net sacrifice of margin per customer, because we can see the difference in margin per customer from gas and electricity. But you'll know in New South Wales that, from the beginning of this financial year, there's a roundabout a 20% increase in gas tariffs. And gas contribution per customer in New South Wales for example was less than half gas for electricity, up to last year, and is now -- gas is contributing probably more than three-quarters of the margin that electricity does. So that rotation will work better and better for us as we go forward.
But overall our net customer position about constant, and to the extent that there's a bit of a rotation of electricity gas under that, that is becoming less of an issue, more of an opportunity as we look ahead. Overall you can see, on the right-hand side of the chart, not much net change in our customer positions either across the market at large or within each state.
It has -- there are a couple of features that are set underneath that activity. Clearly the major retailers are essentially all withdrawn from door-to-door activity. And I think the key I think to note here is two-fold. Firstly, I think it would probably be true of all of the tier 1 incumbents, that our churn is less than market; our customer base, if you like, is more sticky. And in part that's because, as we've invested in systems, our capacity to deal with our customers and retain customers is getting better and better. So you can see between 2013 and 2014 a greater proportion of retains and a lower proportion of wins. That manifests in a lower cost to serve overall, particularly through a lower cost to acquire, and a more efficient operation.
So we are seeing a change in the way the market's operating, but of course we're still seeing a lot of tier 2 competition, which is driving that discount activity that we talked about earlier.
If we go to cost to serve, I said the other major variance in the energy markets business was, firstly, in the electricity segment, the other one being in cost to serve. And on the surface of it, the costs are up $67 million. And this table reconciles that difference.
And the first and really important point to make is that our actual, if you like, our cash cost to serve or our cash cost per customer is actually down 6%. So we've talked to you about the fact that we will drive a reduction in cost to serve, and we have $34 a customer, as you can see on this chart.
But of course what happens, we've talked about this before, is that following the acquisition of the New South Wales business, is we created a provision, this transitional services agreement, where we paid the New South Wales government to build the new South Wales customers until we got them off the government systems. And to the extent that that was out of the money or in excess of our costs, we created a provision.
We did talk about the fact in last results announcements that we made that transition off those government systems nine months ahead of schedule and saved $100 million. So we actually saved payments of $100 million. But we're essentially therefore over-provided by $100 million, so the provision was right, it's just that we did a lot better. And the greater part of that was written back in the prior year, so you see $106 million variance year on year on the write-back of that provision.
So as a result, the P&L shows bottom line that $67 million upward variance in cost to serve relative to the prior year, whereas the actual cost to serve is down 6%. And that's why I say, very good results in terms of operational performance, regrettably year on year in the P&L it looks like an increase in costs.
In Retail Transformation, I think it's fair to say, Frank, that that's now behind us. That investment is complete. And all of the stabilization activity following that investment is complete. And whilst again I won't dwell on detail, a lot of the operational metrics in the business substantially better, and particularly our debtor performance is now back to where it should be, will and can get better again, but it's back to where it should be following that stabilization period. And that in part has contributed to the increased cash flow out of the energy markets business, which in part has contributed to the increased cash flow in Origin. But all of the key metrics for us are now beginning to improve substantially as we will drive both cost down and improve the what we call the customer experience right across our retail business.
Now if we turn to Contact Energy, really just a couple of key points. Again, EBITDA are up, for reasons I'll explain. Well, essentially because there's been a full year contribution from Te Mihi, but part of that contribution has come from compensation payments for the late startup. But in the EBITDA level, that EBITDA for FY14 is a right indicator of the EBITDA generation in Contact Energy's business.
Operating cash flow is strong, and you can see growth CapEx diminishing. And again as we'll talk about shortly, as we look forward, that growth CapEx drops away even further in Contact. So again, Contact, like our energy markets business in Origin are becoming increasingly cash-generative businesses with very little CapEx requirements.
If again we look at Contact's margins, unit gross profit up 6%. Gross profit per customer up 8%. So, not quite the same impact from some of the volume issues, particularly the weather-related ones that we see here in Australia. What you can see of course is that contribution per customer is much higher, and that's because Contact effectively generates all of its own energy from a largely renewable portfolio, with a very low, marginal cost of generation. That is why Contact's business will be a very strong cash-generating business going forward, with very little requirement for reinvestment.
And that point is shown in this chart where you can see an increasing amount of hydro and geothermal generation in Contact's mix. And importantly, that is creating more value because we've had for six years this problem with interconnectors between the North and South Island that was fixed during 2014 with new transmission capacity. And what that means is Contact's hydro in the South Island now gets the full value of, if you like, the North Island price. So not only is the volume of renewable energy in Contact increasing, but it's getting a better return on that volume because those transmission constraints have been removed.
If we go to our E&P business, and again as Karen mentioned, a very, very strong performance. And in fact, if you look at the operating cash flow, that is a better indicator of that performance, where it's more than doubled. You don't see that same doubling in EBITDA because there was a lot of extra provisioning of exploration taken through where cash had been actually spent of course in prior periods.
So as I say, the operating cash flow is the best way of looking at the performance in the upstream business. And effectively that was driven by high levels of availability and strong demand from the market for gas, and of course associated liquids production. So, a very, very good result.
Of course in our upstream businesses, we're still investing CapEx, and in fact looking forward, we'll probably invest more, and again I'll talk about that in a minute, as we chase some of the growth opportunities we have within that existing business.
You can see here simply the production story, up 17%. Importantly, reserves, primarily through Ironbark, work at Ironbark replaced production. And I think very importantly, a set of opportunities in the Cooper Basin, tight gas in the Cooper Basin shale in Northern Territory and conventional in the Browse Basin were all secured during the year. And particularly in respect of Browse, the first two opportunities being secured by farm-in, but particularly in respect of Browse, that acquisition, as I say, or as Karen and I both said, will be funded through the issuance of that European hybrid, assuming the market is robust enough for that to occur, which we think will be the case.
Now in LNG, it's not really a story of profit or EBITDA, it's very much a question of whether the project's on progress. Clearly the contribution we've made to that project funding contribution through to APLNG of $2.8 billion is a huge step-up from the prior year -- prior year, in part because Contact was drawn down project -- sorry, not Contact -- APLNG, which drawn down project finance within the vehicle. So the level of contribution that we Origin need to make to APLNG is up substantially in 2014 and will be 2015, Karen, and therefore that's why we need to conserve our cash flow and redirect that cash flow to funding that investment. And that together with our existing undrawn facilities will see us fund our way through APLNG to first LNG production in mid-2015.
Also importantly, there was strong reserves growth, and I'll touch on that in just a little minute -- in a minute.
This chart, and you can see detail in the OFR, about $21 billion spent now, heading towards that $24.7 billion. And we're comfortable that, you know, plus or minus a bit, we're in line with that number. And importantly, we remain on schedule. And we do indicate the other areas of expenditure, as I say, in more detail in the OFR on things like the existing domestic operation, and I think we identified exploration and appraisal expenditures as well.
So we're really in the last year or so of funding money into the project. As I say, APLNG should commence LNG production around mid-2015.
David wanted a lot more photos in the presentation, and we've put them in the attachment. So I won't delve on this, lots of photos at the back of the presentation, the appendices, to show you that your money is getting your mettle [ph]. You know, there is a lot of asset now on the ground. And I won't go through all these points other than to say that they evidence to you that progress upstream, 76% at the end of June, and progress downstream, 75% at the end of June, is very much on track. And I'd say, David, by the end of August we'll probably be well over 80% progressed in respect of APLNG.
From a reserves point of view, I think it's very important because we saw quite a reasonable movement in our reserves position, upward movement in our reserves position. We're currently reporting 3P reserves at 17.5 Tcf, which you can see from that chart, if you look at the June 14 reserves position, more than covers our contracted requirements, plus what we called a tail, in other words you just can't produce a box and then finish after 20 years. You need a tail. So we're very comfortable about our 3P reserves position.
And with 14,000 of those reserves sitting in the 2P category, exploration is something that we need to continue to prove out the balance of that reserves and convert contingent to look at resources to look at more opportunities. But we are very confident about the total resource position, the reserves position to support our contractual commitments, and at least the 20-year life for these LNG plants.
And importantly, the performance of wells continues to flow through into that reserves increase, because it's performance now that's driving that reserves growth, as well as exploration. But also it gives us confidence around deliverability.
And to the extent that you might look at the data and sort of look at wells in production and total production and try and draw some conclusions about productivity per well, you can't, because a lot of wells are now throttled back, so our absorbed [ph] results where we talk about say 1,200 terajoules a day is what we will get from these wells, but they're not clearly producing at those levels because many of them are throttled back, they're commissioned, they're brought online, and then throttled back because of course we don't yet need the gas to go after the LNG plants Curtis Island.
So I said, downstream 75% complete. Again all the milestones have been met. And on the occasions where we don't, they're generally not on the critical path, and that's why we're still preserving to mid-2015 schedule.
I did not in my introductory comments, we've made no actual hard copy comment in this presentation, that for many years, when asked by investors what worries us most about APLNG, I've been pretty clear around the fact that the EBA for the main unions on Curtis Island was up for renegotiation in mid-2014. And you'll know that there was a little bit of activity around that.
But having said that, it was approved by the workforce and a vote on Friday last week, and I think that reflects that the Australian workforce can get behind these projects and make sure they work effectively. And it's a real milestone to get that issue behind us. And that's why, again, we continue to maintain confidence about our ability to hit that mid-2015 schedule.
Setting a bunch of milestones there for the coming year. Clearly we'll report on those through our QPR and site visits. But again they just reflect that those things that need to be done will get done in time for that 2015 schedule.
So what I'd like to do now is just talk perhaps a bit more fulsomely than in prior years about prospects for the period ahead. And I mentioned in my introductory comments that we're slightly refocusing our priorities. Very clearly now improving returns in our existing business, energy markets businesses, really delivering the growth that sits in the gas businesses in Origin, particularly APLNG, and obviously our upstream businesses, and creating opportunities and growing our investment in renewables. And very, as I say, very much a focus on making sure that that manifests in increased distributions to shareholders. So I just want to touch on some issues that go to how we might do that, and hopefully provide some context for thinking about what our business will look like over the next couple of years.
Firstly, we need to talk about what's happening in the wholesale electricity market in Australia. And what this chart shows is that we've been through a period, 2012, 2013, 2014 where we've seen the highest level of, if you like, excess capacity in sort of any reasonable historical period. And what that means is, in an over-generated market, that returns from the wholesale market, the generators has been low. And effectively those generators, through their retail businesses, have been tracking into the retail business and chasing retail margins. And that is what's driving competition.
The other tier 2 retailer is APG last year, it was bought by AGL. And as I think will be well-known in the market, Lumo [ph] is going through a process which we suspect will probably see Lumo [ph] be bought by an existing incumbent. You never know but that's what we suspect will happen. So we do expect to see that the tier 1 retail -- tier 2 retail participants will probably consolidate in some way, and the major tier 2 activity will come from tier 2 retailers attached to generators. Generators trying to improve returns from the market.
Now the market operator, AEMO forecasts that there are a series of planned withdrawals of capacity in the market, and we've talked about this over the last year, at least in our discussion with investors, that we do expect this excess of supply to rebalance. It will happen through capacity withdrawal, and you're seeing more and more evidence that that's likely to occur, as is forecasted in this AEMO chart.
The second reason it will happen is the rotation of gas from power generation into LNG. And our assessment is that that will swing demand by about 15 terawatt-hours a year. Roughly half of that is increased demand for electricity following electrification of the LNG plants in Queensland, and about half of it is through the withdrawal of gases that recycles off to LNG production. That will also materially alter the supply/demand balance. And of course the big question still outstanding is what will happen with the RET review which of course is forcing excess energy and excess capacity into the market which AEMO, the market operator, has clearly said is not necessarily for probably at least ten years.
So we do believe that over that -- probably that 2016, 2017 period, we will see a rebalancing of the market. We will see that supply/demand balance or that net position on the chart restored at probably historical levels and maybe a bit better. And remember that there always needs to be an excess of capacity, so don't be worried that that still shows a net position above demand, because there's always excess capacity in the electricity market. But the balance should restore through to 2016, certainly into the 2017, 2018 period to more historical levels. And that should improve the competitive dynamics in the electricity market.
Interestingly, New Zealand, the same phenomena happens because methanol plays the same role in New Zealand. So as New Zealand has moved to more and more renewable generation, that's in one respect straining gas. But of course our gas is going off to methanol, as you can see in those charts. And therefore gas as a marginal fuel is really worth what methanol is worth and Australia gas as a marginal fuel is worth what LNG is worth, but both have the same effect of tightening the gas markets in Australia and New Zealand, and that impacts the supply/demand balances in the electricity market. And that should also therefore improve the -- not just the competitive structure but the wholesale price outcomes in the electricity market in New Zealand as well.
I think the key issue for all of us in the industry is the rate of decline in consumption. At what rate? For how long? And to what level?
The rate will diminish and it will diminish -- and is already diminishing, or the rate of reduction is diminishing as the amount of solar installation falls. But trends like in efficiency I think are here for the long term, although of course it won't go to zero.
I think there are really two key issues for us to call out in respect of this trend. The first is that it really does place pressure on a lot of the regulatory and policy settings in the industry. Firstly, we are seeing retail price deregulation now occurring across all the markets. That's important because it lets retailers set prices that are truly reflective of costs, and then compete around those prices as you see happening in the market.
The RET scheme is being reviewed and does need to be reviewed. And we know that we're expecting shortly to see the report from the review committee. There's much speculation about what it will say. At the end of the day [indiscernible] being quite clear in saying that the current 41 terawatt-hours is way in excess of any reasonable -- way in excess of what was intended. So we're looking forward to seeing where that review goes.
It also requires a review of network pricing and regulation, which is occurring. Because of course, as consumption or network-based sales fall, it does change pricing on networks, and there needs to be a movement towards a more capacity-based approach to pricing for networks, and probably suggests within the industry there does need to be a conversation about capacity-based pricing even for generation, if there's to be enough supply to meet peaks in the longer term.
So, firstly, that structural change does require significant review of a lot of the regulatory and policy settings in the market, all of which are occurring and all of which should see the market operate in a much more economically efficient and correct basis.
The other thing that companies need to do and Origin is doing is adapting the products and services that we offer our customers, to make sure that we can respond to that change. So we're in the process, let me say, of revitalizing our solar business. One of the negative variances year on year is less contribution from our solar PV, our rooftop PV installation business. We're repositioning that business, introducing some new products that we will expect to see that business grow again, and we'll see Origin play a more significant role in solar installations both domestically and commercially.
A lot of work going into our metering businesses, new applications like electric vehicles, and also our distributed generation business as well. So, a lot of activity in developing products and services that reflect this change in nature because one of our objectives is to make sure that Origin maintains its share of our customers' use of energy at a household or domestic and commercial and industrial level.
Sorry. I should say just before I move on, I do need to call out, and I notice that our friends at AGL have done the same, that the review of the removal of carbon of itself is pretty predictable, pretty straightforward, but it has had an impact in conjunction with the uncertainty about the RET target on potential earnings going forward. We don't know what the outcome of the RET review will be, but the market is not adjusted for the removal of carbon with no commensurate increase in the RET price. And that's a feature worth noting and calling out. If that persists, then that will increase risk to earnings for all of us in the business who've essentially met our legal requirements to provide renewable energy and contract or invest to do so.
At the moment, we don't see there's a huge risk in the coming 12 months, but if we don't get a sensible outcome in terms of that RET review, the uncertainty will persist and does pose a bit of a risk to earnings. It is a slight risk to next year's earnings, not hugely material, but it's a longer-term risk in terms of the positions we all hold and the investments we've made in renewable energy.
With the completion of Retail Transformation, we are now well-placed to do two things. Continue to drive the actual cost down. As I've explained earlier, that will be concealed by the movements in the TSA provision. But that provision ends this year. It's gone now in 2014. There'll still be a relatively to 2015 where it will be zero. But our underlying cost to serve we intend to keep driving down simply through the hard work of continued improvement in all those processes that drive our cost structure. We have a good idea of what we need to be to be at benchmark levels or certainly world-class levels, and we're well underway to getting there. But that will see a continued reduction in our operating -- actual operating cost per customer, a little bit concealed by relative movements in TSA.
Importantly, in respect of what we broadly call customer experience, again we now have the platforms and technology to significantly improve in broad terms how customers interact with Origin. The bills are right, they're on time [indiscernible] basic that's happening. Customers can increasingly act with the company through a whole range of digital technologies online or through mobile applications. Our service offerings through extended call center hours and flexibility around payment options is much greater. Our communication with customers is simpler and more effective. And there's a lot of work in our call centers on improving right across our retail business our customer culture.
So we believe we can continue to drive improvements in our operating costs, a little bit concealed by movements in TSA, and in part helped by continual improvement in the customer experience which reduces churn, increases customer loyalty and improves our cost position as well.
I think the story around gas prices is well-known. We will see an improvement in contribution from our gas businesses because the long position if you like, the long contract and physical position Origin holds supports our business through end-of-the-retail business. And we've added to that through the year by both acquiring more gas under long-term contract, and certainly more gas under long-term contract, and that's essentially adding significant margin into the business as LNG in Eastern Australia calls for more gas.
Similarly, in New Zealand, Contact looking forward will benefit from an increased amount of renewable generation. And hopefully not too subtle but key point to make here is that Contact can generate more energy than it needs to sell its customers. In prior years it had to because it had take-or-pay obligations for gas and therefore had to run its gas-fired generation. Contact is now no more burdened by -- now no longer burdened particularly by those take-or-pay obligations and can now simply choose whether it runs that generation. It will only run it when it's profitable to run it. And that together with the fact that most of the energy it now sells its customers which comes from renewable energy, geothermal and hydro, effectively has a very low marginal cost. And all of that improves Contact's flexibility and the confidence we have in Contact's cash generation.
Again to draw out a point that we've made before. The amount of capital that is going into these businesses is reducing significantly. We've really made no major capital investment commitment to these businesses over the last probably two or three years. We've completed the investments that we've committed to make two or three years ago.
And so, consequently, the free cash flow that comes from these businesses after growth CapEx is growing significantly and will grow in the years ahead as well. And that of course initially will help us fund our commitment to APLNG. But of course, once that commitment is fulfilled, will add to the very substantial cash generation we have available to increase distributions to shareholders.
The gas story, I think is well known. Gas in Australia is good. We have deep channels to domestic market and particularly deep channels to export markets, with gas or LNG production in Eastern Australia, Gladstone and Darwin, and in the Northwest. And Origin has clearly been seeking to increase its exposure to those opportunities.
As we said before, APLNG is on track for mid-2015, and at that time of course it starts to produce LNG, ship LNG, earn revenue, and ultimately distribute cash flow and earnings to its shareholders, obviously Origin of course. As I mentioned earlier, a strong resource position behind that project.
In respect of the rest of our gas opportunities, we see a number of midterm opportunities that we'll begin to spend money on this year, increase -- two more development wells in the Bass Basin, and continued development through to a final investment decision on Ironbark for example which I'll touch on later on, and exploration drilling in the Otway Basin which we're about to spot [ph] shortly a well called Speculant.
In the longer -- medium to longer term, those opportunities will turn into earnings. The joint venture with Senex in the Cooper Basin, the joint venture with Falcon in the Beetaloo Basin, that's a longer-term one obviously. In a very -- sorry, in the short to medium term, opportunities in Ironbark will all result in increases in that probably 2017, 2018 period. And of course we've completed the acquisition of the Browse interests with joint venture partners Conoco in particular. So we do see quite a number of opportunities for the future in that business.
And finally on renewables, the company clearly through its investments in Contact has very substantial capabilities. We intend to keep building those capabilities. We have a portfolio of opportunities in New Zealand, Chile and Indonesia which will not take a significant amount of capital in the next year or two but which will continue to be developed, significant opportunities for the year ahead.
So in terms of drawing it to a conclusion, this is a transitional period. These next two years are going to see a very different Origin emerge by the end of 2016 and into 2017. APLNG will be completed and will make a significant cash and earnings contribution to Origin. We indicated for some time we expect about $1 billion a year of cash to be our share of distributions from APLNG.
As the requirement to invest falls away and as the earnings come forward, we will be increasing distributions to shareholders, and Karen has shown through that dividend and free cash flow slide. But in a sense we already could, but to do so would be unwise because we're entering those last 12 months of a very heavy funding commitment to APLNG.
We have and will continue to maintain an investment grade credit rating, and that will influence our approach to debt markets, how much debt we have in the book and whether or not in the rate at which we retire that debt.
And having taken into account those two considerations, we do always keep an eye on the future, to make sure that we do have opportunities to continue to grow the company and to recycle some of that surface cash into that growth. And I do think it won't be long before you're asking us to talk to you about those sort of opportunities, and we think the company is again becoming quite rich in opportunities to drive growth beyond the investment in APLNG.
We continue to reinforce that our dividend or that an appropriate dividend expectation is a part of at least 60% of underlying earnings per share. Obviously our earnings per share will increase as APLNG contributes to earnings. And obviously our cash flow per share, as you can see from the prior chart, is very, very strong and will support clearly a higher payout in absolute dollars to shareholders.
Just some comments on what you might expect in terms of earnings for the coming two years. And frankly this year, 2015, is going to be a bit hard to call because the timing of other projects coming online in Queensland and our own project coming online will have quite significant impact on actual earnings outcomes for the year. So we will be selling gas to other projects like QCLNG, we're buying ramp gas, there's a margin -- buying gas at the moment is cheaper than selling it. So there's quite a spread on those costs and revenues. So there's going to be a lot initially that will be driven by timing that's a little bit beyond our control, particularly in respect of other projects.
But having said that, some specific commentary. We do expect our energy markets business to make a material improvement in its contribution. Looking at Frank, I'm not -- we might even get to significant increase in its contribution in the coming year, driven primarily off the strength of the gas position in 2015, and we do expect to see a moderation for reasons we've explained and the competitive conditions in the wholesale market which we expect will flow through into improved contribution from electricity in 2016 and beyond.
Contact Energy again has made the capital investments in Te Mihi and in RT, Retail Transformation. It will increase its contribution over the next two years. The next immediate year, 2015, it has already in its results a full year of Te Mihi because of the compensation payment, so 2015 will have to carry a full year of depreciation interest attached to that. But Contact will certainly increase both its cash generation, its contribution over the next few years.
Importantly and probably a bit of a surprise to what some of you might be thinking, but there will actually be a reduced contribution from our E&P segment in 2015. We've held back on some investments, and that's in part why we've had such a good result in 2014. But we do need to drill some development wells in BassGas and some activities in Otway, in particular, and this will see our production from our upstream assets reduce a bit. It's a very sensible decision for us to make because in 2015 the market is actually long gas because of the amount of ramp gas in the market. And as such, it doesn't make a lot of sense for us to produce into a lower price market on a spot basis, so we are taking the opportunity to spend some money on our upstream assets to maintain productive capacity for 2016 and beyond.
That's particularly around, as I say, the BassGas and Otway assets. And we do also expect probably Cooper won't make quite the same -- made still a contribution this year and may not, for lifting reasons, that is what our customers are calling for, make quite the same contribution. So that's really a 2015-only effect, we expect an increase in 2016, but I need to call that out.
Quite obviously, and we do find, so I'm making a fairly obvious statement, that if we invest the capital, you'd expect depreciation to go up, and I'm sure you all know that. But we do find when we look back that the market tends to underestimate depreciation, so hopefully that's a strong enough clue for you to look at that calculation carefully.
Importantly, the other thing to call out is that whilst we're really quite confident about LNG production commencing in mid-2015, and frankly, whether that means June, July doesn't matter. There is going to be probably two months, David, between first LNG production and starting to make commercial shipments. Maybe that will be less if things go well. But for that reason, even if we were early against our mid-2015, it won't contribute profits because early revenues will go against costs, so it won't contribute to profits in our view in 2015. But of course 2015/16, it all happens from nothing to everything by yearend. And in 2017 we clearly have the two trains flat out contributing.
So in summary, we really do think the next two years are going to be fascinating years. They are, as I say, transitional years for Origin. Between now and the end of 2016, our earnings will increase dramatically, our cash flows will increase dramatically, and our distributions to shareholders should follow, and that's certainly our objective.
We're comfortable that operationally the business is executing a lot better than it has ever done. We do feel we have an understanding on the key issues that affect our competitive dynamics, particularly in our energy markets businesses. And we have I think lots of ideas and plans to improve outcomes in that environment. And of course the team both in Origin and in Conoco that are operating upstream and down execution are doing a fabulous job. And frankly, from my point of view, one of the biggest risks I think is now behind us, and we're looking forward to that project to proceed to first production around mid-2015.
So, thank you very much for -- you had no choice but to listen because you can't ask questions because there's no one in the room. But thank you very much for hopefully listening patiently to that presentation. And what we'd like to do now is to go to questions, and I'll hand over to my colleagues who manage the Q&A process.
Thank you, Grant. The first question for you comes from Jason Steed of JPMorgan. Please go ahead, Jason.
Jason Steed – JPMorgan
Hi. Good morning, Grant. Good morning, Karen.
I have a couple of questions, perhaps if I can start with what appears to be a somewhat cautious note regarding your expectations for electricity, in the year that we're now into, perhaps Frank can answer part of it too. Back at the half-year, Frank, you talked about the hedge book probably being scaled back, running a bit more of an open position to the pool, in which case you'd expect to see the wholesale energy cost probably dropped down to a meaningful extent in this year. And then coupled with that, obviously volume improvement based on a normal year. As we look at that, do you think that electricity should be -- should play a part in that significant improvement that you referred to, Grant? So, just a bit sort of surprised at the cautious note being struck around electricity, so maybe you could set me straight. That's the first question.
Well, why don't I ask Frank to answer that, will comment on that question, I'm not sure you'll answer on it, but you'll comment on it, Frank. Jason, if you're happy, we'll get Frank to comment on that one first.
Okay. Hi, Jason, it's Frank. So you're right, in terms of the wholesale market dynamic, you're right. You would be able to observe where pool prices are today, particularly in the Queensland market, so we would expect to see a continuation of that theme, particularly with the abatement [ph] of gas about in terms of electricity prices being lower over the course of 2015. Clearly the timing of LNG projects and so forth could change that dynamic, but we do expect that for the majority of 2015. So, not expecting upward pressure at all in respect of those pool prices. And as you say, we wound out some of that hedge position over the last 12 months, 18 months.
So from a cost of energy, we'd expect that. And so I feel reasonably confident in that regard.
One of the things is we continue to run a short position. And the way I'd like you to sort of think about that this year is that we really are sort of leaving our book flexible to the fact that there isn't abundance of gas at cheap prices, and we will utilize our gas generation over the next 12 months, but we're leaving that flexibility within our portfolio to enable us to do that. And those prices are pretty attractive at the moment.
Probably the call-out then is, if you talked about, that's right, you've got a rebound in weather, so in terms of volume we would say that. Offset against that, really the only other key feature will be the impact of carbon. And probably the way I'd leave you with the message of carbon, it will have an impact because we have a lower intensity portfolio generation in energy markets. And whilst that's not anywhere near as large as our competitive impact, it will have an impact on 2015. So that's probably the only thing that sits there.
Much as I want to ask Frank a question, he only needs to nod or scream if he disagrees with this, but I think in part our caution is actually over the outcome of RET pricing through this whole RET review process. It's not, in respect of the billions we paid by electricity, it's not billions, but in terms of margin, there's quite potentially significantly different outcomes, and it troubles us a bit that one of our major competitors is flagging the dividend I expected in recovering that price. So if you're sort of reflecting on caution, that's the caution that we're guiding to, Jason.
I just want the market to be aware that the RET review is causing quite a degree of uncertainty about certainly spot RET prices which are what, $30 or something like that. Yeah. So that's actually where I would reflect mostly on the caution, Jason.
Jason Steed – JPMorgan
Understood. And just to wrap up on that question, the -- you would have heard AGL talked about half of the impact that they've seen through electricity volumes coming back in FY15 and their decline wasn't dissimilar to yours. So it seems to be [ph] the rebound at least being 5% on that front, I guess when you look at mass market volumes of [indiscernible]?
Five percent, approximating that 0.9. So we'll definitely see weather come back. I think that weather impact to us this year was about 0.5 of a terawatt, so there's 0.5. I don't have percentages in my mind. We probably think that the efficiency impact over the course of the next year is sitting at around about that 3%, which is consistent with AEMO. So I think the combination of those two, if you look at this year, gets pretty close back to your math there, Jason. I'll just make sure -- I think that does come back in percentage terms to be about [indiscernible]. Okay?
Jason Steed – JPMorgan
Okay, good. Thanks, Frank; thanks, Grant.
And then just a question, last question, being on the hybrid. Purposely, you haven't provided much definition around [indiscernible] raising the equity content terms, et cetera. But it would be so, particularly given S&P shift last year on equity content, the fact that you're negative watch with S&P or out of negative. It would just be helpful if you could try and provide just a framework around what you will raise and what some of the terms might be for that hybrid.
So what we would be intending to do, Jason, is just the absolute stock standard hybrid 50% equity/credit. We're kind of -- obviously the market is on the edge of being opened. It's still some are closed for summer in Europe, so. But indications are that we'll be comfortable looking for sort of a benchmark deal which is 500 to 750 kind of benchmark, as a benchmark for the sort of instrument in Europe.
So the -- it's more the, you know, we're more confident about obviously the strength of the cash flow in the business, the position of the business, and the terms of the hybrid will look like a very standard hybrid. We're not, yes, concerned about rating. Grant said that we have to do it for the rating, I think I heard him say, but I'm not feeling that's the case. It's just appropriate that we go and test the market because it's a better outcome for shareholders if we can be successful there.
Jason Steed – JPMorgan
Yeah. And so, Karen, on that basis, the fact that you -- S&P is not concerned about where you sit in terms of FFO growth [ph], that, given you're still some way below the threshold triple-B, so they're looking through to obviously FY15 and 2016 and improvement there?
Yes. So we've obviously been in discussions with S&P there, aware of what our intentions are, that what we're looking to do. So, no, not concerned about that at all.
So, obviously the watch is around the progress on APLNG and the progress that I pointed to, obviously the progress around energy markets as well. So nothing has changed in that regard. But we wouldn't expect them to change their position until essentially we can see APLNG on -- in the ship possibly, might be the way to describe it.
Jason Steed – JPMorgan
But not concerned. Very relaxed about.
I think that in part, Jason, is because it has been a very strong year for cash, and there's nothing disturbing the schedule. So, confidence builds all the time.
Jason Steed – JPMorgan
No, no. Good to me. Great. Thanks, Graham. Thanks, Frank, Karen.
Thanks, Jason. The next question comes from Mark Samter of Credit Suisse. Please go ahead, Mark.
Mark Samter – Credit Suisse
Yeah. Morning, guys. Just have a couple of questions. Starting on APLNG. Looking at the numbers you provided, you've got about AUD3.7 billion left in the budget. I guess you spent $3.9 billion in the previous half. Just -- and I know [indiscernible] have 32% of its budget left with 15 months to go with it [indiscernible] last year, you've got 18 months left. And also [indiscernible] get to the numbers. But [indiscernible] it looks like they guided towards about a $2.5 billion cost increase versus current expectations from you guys with APLNG. Just wondering if you could put that all in context.
Mark, it's David here. Look, I'd say that, starting with the Conoco perspective first, I think our colleague in Conoco, when he's making his announcement some months ago, referred to quite a lot of contingency that they're to decide, in case things, you never know what happens, are sort of the words he used. So -- but he also made the comment that they were comfortable with the forecast in terms of the budget, as we are. And that remains the case.
I can't off-the-cuff do a comparison between where we are and QCLNG as you say. But what I can just reinforce is the fact that our budget is -- we're comfortable with where we are with the work to proceed, in the 80-odd-percent, Mark, as we speak, and pretty clear out between now and the end of the project over the next 18 months or so.
I think, David, just we did call this out in the OFR that probably one of the risks again, if we got back to where are the risks and what risks we worry about, I think one of the things we called out is we're probably -- see some risk around what we call the non-operated area such as costs coming through from projects we don't operate, so we can have a lot of confidence about what we and Conoco are offering, because we got direct line of sight. So that's a risk, but at the moment we only know what we know. And David's comments are right in respect of what we know. But if we're focusing on where's the risk, we're saying if that, you know, it's important to remember that some of our costs do come through from the other projects.
And we have seen some pressures come through from both of the other projects. Our interest in both of those projects affecting us in terms of our contribution to them. But again that all in the -- in terms of where we forecast the project, including our interest in QCLNG and GLNG look in line with budget.
Mark Samter – Credit Suisse
But can you explain why both of the previous two, I think in the first half [indiscernible] you spent $4.1 billion and $3.9 billion in the second. You're now saying you're going to spend than either of those halves over the next 18 months. Well, why is it slowing down so much?
I'm not sure I got the --
Mark, you've been breaking up a little bit, and that's not because we're -- that's not a matter of being so we can avoid the question, but you are actually breaking up a bit.
But I think in respect to what I think your question is, it seems like we've got less to spend than the others have got to spend. I suspect you'll find the answer is that upstream we're very well advanced. We're not chasing gas resource, we're in really good shape upstream.
Mark Samter – Credit Suisse
Sorry, I'll try again [indiscernible] my handset now. I guess why is it decelerating so quickly that you will spend less in the next 18 months than you spent in either the previous two halves?
Well, not unusual for projects, and ours is not different to others. There's an S curve, and as we get into the end of this calendar year, the downstream will be close to 90-odd percent, and the upstream in the same place. And as we get into the 80s, the high 80s and the 90s, the rate of spend reduces, as we head towards completion.
Mark Samter – Credit Suisse
Okay. Just another question, domestic non-project CapEx has gone up by about $420 million versus FY13. Can we just get some clarity around that?
A couple of things driving that. One is -- the main one is actually sustained CapEx, and we've referred to the fact that we've been bringing forward, accelerating the CapEx for the sustained phase in order to not pause, if you like, between the completion of our phase one wells and the commencement of the sustained phase. So that's the largest part of that portion.
Mark Samter – Credit Suisse
Okay. And then just one more question --
Just again I'm looking at David, and he'll disagree if he disagrees to the comment, but what we call domestic includes the 648 gas sales to BG.
Which is a non-operated project. Yeah.
Mark Samter – Credit Suisse
Okay. And just one final question, again you can spot the oil and gas, I'm just asking all the questions around APLNG. I mean when I look back at the I think last 12 or 13 greenfield LNG projects built, I think seven of them have been delayed and the vast majority of those were more than nine months delayed. I know that the EBA issue has been resolved, but productivity has to be a major question from the 3,100 workers that voted no three times. What gives you confidence, and you sound increasingly confident, I'm just -- I'm curious to help us understand why that increase in confidence that APLNG is going to be different to the average LNG project.
So just to be clear there, voted no twice and they voted yes the third. But we actually didn't see, but for the disruption that did occur in the last -- leading up to the vote last week, and that was felt by APLNG and the other two do [indiscernible]. There wasn't, you know, there was certainly some workers affected by that, not many.
We actually didn't see really any drop-off of productivity leading into that vote, and we have not seen any deterioration in productivity since the vote. So contrary to what you might -- what your question implies and what is not an unreasonable perspective, we haven't seen any deterioration in productivity in terms of the things we focus on, pipe work, cable laying, the metrics that we can really measure, productivity by, and they are holding pretty well.
Mark Samter – Credit Suisse
I would say one other comment, because just again for abundant clarity, in respect of your earlier questions, to me, I can understand you probably know the rate of spend, but it's very consistent because we called that six months ago that our rate of spend upstream or our progress upstream is such that we were going to keep that drilling machine going and pull forward sustained CapEx. Sustained CapEx is wells two or three years out beyond what we need to bring the project online.
So the CapEx that we allocate against the project is going to come off earlier upstream, but the activity won't, you know, because we'll keep that sustained activity going. As we said, we're not going to de-mobilize a drilling machine we spent two years drilling, when we got to drill average 300 wells a year or something like that, David, going forward. So I'd just call that out as well. That might help you understand the rate of spend issues.
Mark Samter – Credit Suisse
Yeah, that will be part of the Conoco issue. Conoco wasn't project CapEx, it was just [indiscernible] totality CapEx?
Yes, that's right. Correct. I think you got it, Mark, so I think that's right, yeah.
Mark Samter – Credit Suisse
Thanks, Mark. If I can just take this opportunity to remind all other parties that have registered for a question and using a speakerphone, to where possible pick up your handset when asking the question [indiscernible] speakers.
I'll place Dale Koenders through from Citigroup. Please go ahead, Dale.
Dale Koenders – Citigroup
Hi guys. Two quick questions. Just firstly on Ironbark and [indiscernible] of two years on the production chart. Can you provide a little bit more color on the strategy for Ironbark?
Yeah. So I'll ask Paul to give us some more detail, but the broader context is that we'd rather -- we're going to spend capital in best gas. And that way we just prioritize as ever Ironbark, so it's just a prioritization of how we allocate capital. But in respect of that for Ironbark and the pre-feed [ph] activity and the appraisal drilling, Paul, do you want to give an update?
Yeah. Thank you. Thanks for the question, Dale.
This has been a good year for Ironbark this last year. We've drilled some good appraisal wells. We've added almost 100 petajoule good [ph] reserves. And so we've got really quite a lot of confidence in the phased development of Ironbark. What we'll be doing this next year is just extending that, also will be doing some more exploration drilling, moving our regulatory approvals forward. And further on that sort of pre-feed [ph] type activity. So when we -- when the time is right to take FID [ph], we'll be in a good position to do that.
Dale Koenders – Citigroup
What should we be inferring in terms of the delayed timing? Does this mean that the market doesn't need gas, that the LNG projects really don't need gas in the near-term timeframe? Can you maybe provide a comment there?
Certainly APLNG doesn't. In terms of Origin's economic interest, certainly APLNG doesn't. Having said that, we do believe in aggregate the market will probably still be calling for gas. So the first one is APLNG doesn't. The second point is we probably still think on balance LNG will be calling for gas. The third point is that Origin, through its total book, largely managed by Frank, is in a position to supply that gas and swing that gas in fact all the way from Victoria if we need to do so. So by prioritizing productive capacity in BassGas and Otway, any net, if you like, unit of production that doesn't end up in that market will end up in Queensland. And we probably, maybe one other organization could, but just very few organizations that can swing that gas all the way to Queensland.
So we still think the call on gas is good in Queensland. We can make that call across the portfolio. APLNG itself is fine. But from the point of view of just allocating capital, we're still cautious about the rate at which we allocate capital until we get to those cash flows coming out of APLNG, and we're prioritizing the other upstream assets which are already in production, so they will -- like we do also development wells in BassGas. BassGas production will increase the day we open the valve. So it just seems a better prioritization from our point of view.
Dale Koenders – Citigroup
Okay. And then one other quick question. I guess you spoke about the [indiscernible] moving door-to-door sales, and maybe a little bit of a rationalization from your tier 1 retailers. But could you maybe comment on what you've seen in terms of the competitive behavior from tier 2's which seem to really be setting margins [ph]?
Yes, sure. So really seeing sort of two markets at the moment. Victoria remains very intense, and you can see that from that discount chart. So that's -- and we're expecting that to continue over the next 12 months. It's -- and driven, most of the activity in that market is in fact driven by the tier 2's.
If you looked at the churn levels over the last year and where New South Wales is at, there is some tier 2 activity, but lesser, and certainly not the discounts that were in the market compared to 12 to 18 months ago. So we're really expecting Victoria to still be an intensely competitive market.
If I was to give you an expectation overall, we would say that, if pricing or discounting was an indicator of that intensity, we would expect discounts overall to be pretty similar percentage of revenue next year -- this year compared to the one just gone by, or probably different in composition particularly that we'll see, the continued penetration of discounts into the Victorian market. But that's where we're really seeing that activity at the moment. And yes, as you say, that's where the tier 2 is really playing at the moment.
Dale Koenders – Citigroup
Is it fair to really say then that we're not seeing any significant change in the behavior of the tier 2 retailers at this point in time?
Yeah, that'd be a fair statement. They still continue to be active in the marketplace, concentrated in the states, particularly Victoria, and to a lesser extent New South Wales.
Dale Koenders – Citigroup
Okay. Very good. Thanks.
Thanks, Dale. Next question is from John Hirjee of Deutsche Bank. Please go ahead, John.
John Hirjee – Deutsche Bank
Good morning everyone. A question first, Grant, you mentioned Lumo [ph] and you felt that it would go to incumbent. Would you care to comment on Origin's interest in Lumo [ph] as it's up for sale?
Look, we are an incumbent, but we don't believe we would -- well, there are others in the market that should pay more for Lumo [ph] than we would. And we think that's the likely outcome.
John Hirjee – Deutsche Bank
Okay. Thank you. With APLNG, the surplus of reserves that you have against that project is getting more significant, particularly if you bring in Ironbark in that. And given the long lead times, what sort of planning are you thinking about? Any expansion plans at all? Or is expansions totally off the table for APLNG?
So I'm not going to pass that question David because I don't want him thinking about expansion. I want him thinking about getting there in mid-2015.
Look, there's no point. You know, for APLNG, APLNG is not currently planning a third train or anything like that. The focus is just so much on delivery. And I think -- and I know you know this, John, as all of you do, that you just don't take your eye off any of the risk and managing all of those risks through the completion. So, look, there is no current largely active process looking at expanding production capacity.
You know that we've reflected that reserve strength for example can go into other projects should they be short, so APLNG can monetize more gas without having to build the metal. And so, sort of commercial opportunities are probably the next most important thing to focus on given the strength of the resource position.
John Hirjee – Deutsche Bank
Yes, all right. That's clear.
And finally, on energy markets, you indicated that you're pretty well past the Retail Transformation phase. But you indicated that you're looking to extract more returns out of the energy markets business. I guess, is there much self-help you can do in that business?
So the answer has to be yes, because if it wasn't, I should leave and someone else should turn up. So the answer is clearly yes.
Some of it is structural, for the reasons I talked about. We do need to advocate strongly for change through some of the, as I say, regulatory and policy settings, and we're active in those debates. But at the end of the day, I'm looking at Frank, but it's fair to say we will take more out of operating cost.
But it really is ultimately all about margin management. Cost can only get you so far. And that really does come down to how good a retailer we and our competitives are. We've now got the tools to do it. I think it'd be fair to say that, relative to AGL, they're probably farther in their journey than we are, but that just means we can catch up more quickly. And I think we've got tremendous capability to improve all of those things that go to the way we deal with our customers. And that ultimately will result in I think better margins. So that's the first part of it.
Secondly, by limiting capital -- look, I don't have the numbers precisely in my mind, but our stay-in-business CapEx in energy markets is way less than our depreciation. So in essence, being very careful about capital allocation, the business returns will also improve. So it's a lot to do with how we allocate capital to those businesses as well.
So, margin management, capital allocation, being very active in the review of what we call policy and regulatory issues that affect the business or at least three areas, and -- sorry, gas. Well, Frank's just calling out the gas, and I've sort of taken it for granted, yeah, but gas is clearly [indiscernible]. Could I share as well, gas is not just selling gas off to the LNG projects. We said for a number of years there's no intrinsic reason why the gas contribution per customer would be any less than electricity contribution per customer. And part of the need to get rid of price controls is to allow that re-waiting [ph] to occur through time as well. So I think there's quite a lot of things we can do to improve that situation.
John Hirjee – Deutsche Bank
Okay, Grant. Thank you very much.
Thanks, John. Ian Myles of Macquarie Equities. Please go ahead with your question.
Ian Myles – Macquarie Equities
Hi. Good morning guys. Just continuing on that theme. You make the comment about a 15 sort of terawatt-hour swing in electricity through the opening of the LNGs. But when you think about that, most of that swing is occurring in Queensland where you're actually short energy. How do you see that actually transpiring into higher wholesale prices for the rest of the market?
And I guess the second issue which comes about, the general theme between AGL and Origin is the promotion of higher wholesale prices. What sort of leverage do you see coming through your broader energy markets business if you can see these electricity prices move out $2 to $3 a megawatt-hour?
Well, I'll pass over to Frank, and then if I think I can add any further value, I will. But Frank, you have a shot on that, and then -- yeah.
It looks like you're ready to say something, Grant. But, so just the first thing, so the upswing that -- when we look at that swing, you're right in broad terms around the -- what we see. We see gas generation coming out, of which a large -- a reasonable portion will come out of Queensland. But the gas, that rotation is gas coming out of the market more broadly. And LNG electrification I think we think adds about sort of 7 or 8 terawatt-hours. So that's how we see that rotation.
As that tightens, currently you've got Queensland electricity pumping into the New South Wales market. We would expect to see that remove itself. We would expect to see some uplift in Queensland, but also you'll see a recovery of the wholesale price in New South Wales. The recovery of the wholesale price in New South Wales will flow through to our contribution from Eraring. That's essentially how we'll get leverage to that.
And clearly in the intervening period, while that rotation occurs, clearly we're utilizing our Darling Downs asset and our flexibility of the transmission of gas to in fact make sure we optimize margins between gas and electricity over that next 12-month period as well. But that's where our leverage to the rotation will be. And we don't have any base load coal in Queensland.
And I'd just, if I could ask Frank a question, I don't have the answer to this question, but I think the capacity factor, AGL has talked about this and about Met [ph] and benefiting from that rotation. I think MetGen's [ph] capacity factor is probably higher than Eraring's.
It is. We currently run Eraring at around about somewhere between a 50% and a 60% capacity factor. MetGen [ph] will be running much higher than that. And obviously, as you know, that doubling could just [indiscernible] go into the future as well.
Yeah. So for the reasons that Frank's explained, in a sense we should get more uplift out of Eraring relatively speaking because it's got a greater ability to run more as gas is withdrawn. So that's why we feel pretty comfortable about that rotation.
Ian Myles – Macquarie Equities
Okay. One other question. In terms of the timeline, the -- with a lot of the LNG dumping of gas at the moment through the electricity market, is it the first LNG plant which will bring the market back to balance, or you need to actually see GLNG and APLNG actually start up before you moved to a balanced or even short position?
We would expect to still see ramp gas available in the market beyond the first -- completion of the first LNG project. So we still certainly see. Our current view is to still see some volumes associated with that until APLNG comes on.
Ian Myles – Macquarie Equities
Okay. Thanks a lot.
Just before we went to the next question, I noticed it's 11:25 -- great. I was going to say we'll got to 11:30. There's certainly one more question on the line, but if we do cut it up at 11:30, I apologize, but I know people will, yeah, want to get on and do other things. So we'll take another question. Thank you.
Thanks, Grant. A question for you from Simon Chan of Merrill Lynch. Please go ahead, Simon.
Simon Chan – Bank of America Merrill Lynch
Thanks. It looks like I just sneaked in.
Frank, I was wondering if you could be a bit more specific on the issue of penetration of discounts. I remember 12 months ago we had the same conversation on the call and you were suggesting about a third in New South Wales and indeed a third across your portfolio. How has that changed now?
Okay. Over the last 12 months, in aggregate, it hasn't changed, Simon. What has occurred is that the penetration into Victoria has increased. And if anything -- and New South Wales has come off. So we have in an aggregate not changed. But if you do the maths, you'll know that there's higher discounts, if that makes sense, playing out in Victoria, and that's actually increased.
If I was to proffer a view over the next 12 months, I would expect to see that that penetration continue to increase in Victoria, and therefore we'll have some I think modest but small upward pressure on that penetration. But we are still not more than a third, in fact a little less than a third across our book.
Simon Chan – Bank of America Merrill Lynch
Great. And next question's probably for Karen. But in the past you guys have put in a slide on CapEx outlook, as in a year ahead. I can't seem to find that today. I was just wondering if you can give me a feel in terms of dollars, millions of CapEx next year, I mean aside from APLNG.
Yes. So we haven't used that slide for some time, Simon, but we all remember it. So what we said last year was that this year's CapEx would be about the same run rate as the prior year. And outside APLNG and outside just the purchase of Browse, that we would continue with that statement. It might be a little bit higher because of some of the additional spend on Browse, but about the same, under, you know, somewhere around $1 billion, under $1 billion mark.
Yeah, less that. I mean energy markets and Contact, it wouldn't register on a chart. APLNG, you know the numbers. And our growth cap, I think that this year was $699 million on growth CapEx, so, I don't know, maybe it's a bit --
Specific number. Yes.
-- 699, so maybe it's going to be a bit more. But it's not going to be a billion.
Yes. So --
Excluding Browse. Excluding Browse.
Yes. So as Grant already referenced, the spend is being focused on E&P in Southern Australia, so.
Simon Chan – Bank of America Merrill Lynch
And just one final one, Grant, Halladale, is that -- has drilling there kicked off yet, or if not, when?
Yeah. We're just in the final stages of rigging up right now, expect the rig to be in commissioning at the end of August, and it's probably going to be the first week in September when the well spuds.
Simon Chan – Bank of America Merrill Lynch
Great. That's all I got. Thanks guys.
Thanks very much.
So, ladies and gentlemen, I think -- I don't believe we'd cut anybody off in questions, as best as I can tell. And 11:30 being pretty much the appointed time, look, thank you very much. I'd appreciate a quiet moment, if you could give some feedback to our Investor Relations as to whether this has worked because it's the first time we've done it this way. But hopefully we still had an opportunity to ask all the questions you'd want to ask and hopefully give you some useful answers.
So, thank you very much for your attention. And we look forward to catching up with many of you over the next few days. Thank you. Right.
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