Robert Wilson – Chairman
Frank Chapman – Chief Executive
Ashley Almanza – CFO and ED
Martin Houston – VP & MD, Americas and Global LNG
Christine Tiscareno – S&P Equity Research
Jason Gammel – Macquarie
Jason Kenney – ING
Irene Himona – Societe Generale
Fred Lucas – JP Morgan
Hootan Yazhari – Bank of America Merrill Lynch
Paul Spedding – HSBC
Theepan Jothilingam – Morgan Stanley
Jon Rigby – UBS
Lucas Herrmann – Deutsche
Oswald Clint – Sanford Bernstein
Rahim Karim – Barclays Capital
BG Group plc (BRGYY.PK) Q4 2010 Earnings Conference Call February 8, 2011 9:00 AM ET
Good afternoon, ladies and gentlemen. I am Robert Wilson, the Chairman of BG Group, and it’s my pleasure to welcome you all here, this afternoon, to this Q4 results presentation, and of course, our annual results presentation.
Now, the format this afternoon is going to be just a little bit different from what you normally see. Normally, we have Frank and Ashley making this presentation between them. This year it’s going to be a little different, because we’re having Martin Houston talk to you as well about what’s going on in the global gas markets.
And, the reason for this is that there’s been quite a lot of confusion amongst parts of the investment community about, what on earth is going on in these gas markets here during the last year or so, and even we’re looking at gas prices in the United States, which are about one quarter of their energy equivalent oil price – so one quarter of the price, which seems a bit surprising on the face of it at a time when gas is regarded as a clean fuel and a premium fuel, so why is this happening. And there is also quite a lot of confusion in the market about the so-called threat of a surplus of LNG to going on for some years ahead.
So I think it is very timely that Martin should be addressing some of these issues and provide you with BG’s perspective. Now, I know that some of the analyst here have actually been pretty hard at work on the same challenge, and actually have already come to conclusions which are pretty well consistent with our own. But, nonetheless, I do think it is time for us to clarify a little bit more than we have done so far, our views about the medium and long-term gas market.
Now, the other thing which is slightly different today is that this is Ashley’s last turn as our CFO. Ashley, as you know, has been CFO now for around about 10 years. He’s been a great contributor to BG Group over that period, and there is no doubt we’re going to miss him. And I want to thank you now Ashley, for all you’ve done for the Group, during that period.
Now, one of the things he has done for us is to give us sufficient time to reflect on his plans to workout what we’re going to do after his departure. And we’ve been exceptionally lucky in that sense to have found Fabio Barbosa, who had – just like to standup for a moment, so you can see who he is. And Fabio was the CFO of Vale Energy.
He is probably known to some of you when he’s been over here making presentations on behalf of Vale, and he has one other great quality which is going to be very valuable to us, and that is his depths of experience and knowledge of Brazil, and I think everyone here knows that Brazil is such a crucial part of our future that I’m quite sure we’re going to get great value from Fabio’s insights there as well as a CFO.
Well, with that, I would like to pass over to Frank, to start the program going. Thank you.
Thank you, Chairman, and good afternoon, ladies and gentlemen, and welcome to BG Group’s fourth quarter results and annual strategy presentation.
First, I’ll draw your attention to our usual legal notice, which I’ll leave you to read in your own time later, just before you not off to sleep this evening, I’m sure you find that very enjoyable thing to do.
2010, of course, was a pivotal year for BG Group as the largest growth opportunities in our history began to crystallize. Today’s presentation will provide an update on the progress we’re making with these key projects as well as expressing our views as the Chairman has outlined on the business environment.
Our aim, of course, is to provide you with provide insights into the value and future potential of our business. Now, in a moment, we’re going to begin with Ashley giving us a rundown on the 2010 results. Then, Martin will talk about our perspectives on global gas markets and brief you on our LNG business. Then, I’ll update you on the progress in our major growth projects and talk about the long-term outlook.
Now, to begin with, here is a summary of the key points from last year’s presentation. 12 months on, how have we done with delivery against this program. We’re reaffirming our E&P growth range of 6% to 8% out to 2020. And as I will show you we are now – it is now feasible to deliver the midpoint 7% from our existing discoveries. We are reaffirming our goal of 20 million tons per annum of LNG supply by 2015, and we’ll show today a supply potential of 30 million tons per annum by 2020.
Brazil is larger and of a higher quality than outlined this time last year. It is now BG Group’s view that these fields could support net production levels of 550,000 barrels oil equivalent today by 2020. We’ve sanctioned the Queensland Curtis LNG project as planned, and construction is now underway.
Our US shale gas business is on course to produce 190,000 boe per day by 2015, almost double the level we presented here, this time, last year. We’re increasing our LNG profit guidance, $1.9 billion to $2.2 billion per annum to 2012, profits that we expect to expand further as on the back of the 50% volume increase that we expect by 2015. And we’ve again grown our total reserves and resources base adding another 1.7 billion boe.
So I think it’s fair to say from this that 2010 has been a year of delivery. Now this continuing progress with our growth programs, sustained now over many years, flows from the clarity of what we aim to achieve, clarity about our investment proposition and our objectives and clarity about our strategy. It begins with our investment proposition. We are an internationally diversified integrated energy business with a specialism in gas, and our objective is to grow at rates that are a multiple of the industry average.
The vehicle for delivery this investment proposition is a clear, effective, and resilient global gas strategy founded on a deep understanding of our target markets, and a broad fit of customer relationships. We couple this with skills to identify, to commercialize and to connect to those markets, the long-life competitively priced resources that are the foundation of sustained value creation. Importantly, while retaining our distinctive focus on gas, we are able to adapt this approach. For example, applying our skills and our resources to oil opportunities such as Brazil, and seeking to secure a material increase in our exposure to oil prices, actions both guided by our drive for shareholder value.
Now, the consistent pursuit of this strategy has enabled BG Group to assemble what we believe to be a distinctive combination of competitive advantages. It begins with a focus on gas markets, which we believe are set to grow strongly. We are a leader in international gas marketing. We have strong and a balanced portfolio of both markets and resources. We have a flexible and highly profitable global LNG business. We are a leader in exploration with a track record which has sustained growth in our long-life reserves and resources space. Much of this resource space resides within a pipeline of economically robust projects that are being fast-tracked from discovery through project sanction, to first production. And, underlying this development tempo is a cost structure, which is top quartile.
So, nine sources of competitive advantage behind our track record and our current plans, and indeed supporting the future opportunities that we will continue to create. We have a production profile grounded in resources [inaudible], which we now believe can reach or exceed the upper end of our 6% to 8% long-term growth range. This translates to 1.6 million boe per day in 2020. That would represent an average growth rate of 11% per annum sustained over a 23-year period from ’97 through to 2020.
We see a similar pattern in LNG, with supply growth averaging 21% per annum over a 12-year period to 2015, and we’re now modeling a 30 million tons case. Both of those trajectories have in turn driven operating profit growth by an average of 29% per annum over the last 13 years, momentum that is now on its way to being restored as we recover from the 2008 financial crisis.
Now, we’re going to return to all of these things later, but first to get us going, here is Ashley, to take us through the 2010 results.
Thank you, Frank, and good afternoon, ladies and gentlemen. If I can just begin by saying, as the Chairman has pointed out, this is my final presentation, and I’d like to take the opportunity to thank my Board colleagues, my colleagues in the company, and all of you here in the room today and listening in, for the tremendous support that you’ve shown me over the last nine years.
So let’s take a look at the results, starting with the Group highlights. Group reported good results with operation profit up by 9%, and cash flow from operations up by 10%. Earnings per share rose by 18%, as the operating result was enhanced by lower interest expense and a lower effective tax rate at 38.5%. We expect for 2011, an effective tax rate of around 39%.
We ended the year with gearing of 20% and the Group remains soundly financed. During 2010, we extended our debt maturity profile considerably and we increased our committed facilities. And as you will see from today’s presentation, the outlook for the Group is very positive, with the business well positioned to resume strong growth, and that positive outlook is reflected in the Board’s decision to increase the full-year dividend by 10%.
Those were the highlights.
Now, let’s look at the results in a bit more detail, starting with E&P. Outages on Erskine, Hasdrubal and Panna, meant that E&P production increased only slightly this year by some 800,000 barrels of oil. Realized prices, however, were up strongly, especially in the second half, and our unit OpEx came in line with our guidance at $7.28 the barrel of oil equivalent. And the combination of these factors meant that our E&P operating profit before exploration expense was up by 9%.
Exploration expense was 18% lower than last year and this was almost entirely due to lower well write-offs, and that reflects a very positive drilling campaign in 2010, with our major wells in Tanzania, Brazil, and China, all coming in as successes. In 2011, we expect that our explorations spend will be around $1.4 billion, and you should assume around of this will be expense. E&P total operating profit after exploration expense in 2010 was $3.8 billion, a 17% increase year-on-year.
Now, staying with E&P, let’s look at some of the key nonfinancial metrics, starting with crude reserve replacement rates. In 2010, we had a reserve replacement rate of 224%, and this is equivalent to 529 million barrels of oil equivalent. This is a net figure after deducting 62 million barrels for price effects, mainly relating to Karachaganak. Effects of acquisitions and disposals was a further production of 12 million barrels of oil equivalent. Also adjusting for these effects, the underlying organic reserve replacement rate was 256%, equivalent to 603 million barrels of oil equivalent. And this performance ensured that our competitive position remains very strong indeed.
This next slide shows our one year and three-year reserve replacement rates on the left hand side, and our competitive position on the right hand side. Our three-year reserve replacement rate is 223% and this includes the net positive contribution from acquisitions and disposals. Our organic three-year rate is a 190%. The chart on the right hand side is prepared using independent data from Evaluate Energy. And it confirms, once again, that BG continues to sustain a highly competitive reserve replacement performance.
Now, Frank, will discuss our growing resource position and our projects in more detail in a moment. I’m sure it’ll be clear to you that the rapid growth in our total resource space and the scale and number of our projects in development means that the Group is well positioned to develop, deliver strong reserve replacement rates for many years to come.
Now, reserve replacement rates are, of course, reflected in finding and development income. The left hand side of this chart shows our rolling three-year F&D cost. The industry, as well all know, has experienced rising F&D costs in recent years. However, through cost effective reserve additions, BG has managed to [inaudible] top quartile performance, seven of the last eight years. And we expect that once peer data is available for 2010, our three-year average F&D cost of around $16 a barrel will once again be in the top quartile of our peer group. We also believe that BG’s strong portfolio of projects already in development will sustain our F&D performance well into the future.
Now, the right hand side of this chart compares our units’ OpEx with that of our competitors. Here too, BG has been a top quartile performer for sometime. For 2011, we estimate OpEx inflation in our portfolio of between 5% and 10%, and I think that will once again position us very strongly.
That’s E&P; let’s take a look at LNG. During 2010, we saw demand recovery especially in Asia, and this was coupled with good weather-related demand during the course of the year. In these conditions, we were able to use our flexible supply chain and our market knowledge to divert cargos to high-value markets. As a result, we posted operating profit of $2.2 billion in our shipping and marketing business, and this was in line with 2009.
Operating profit from our liquefaction business was also in line with 2009, coming in at $326 million. Overall then, the LNG segment delivered an operating profit of $2.4 billion.
In transmission and distribution, total operating profit was also similar to 2009 levels, and it came in at $711 million. In Brazil, Comgás saw a strong recovery in demand, with volumes up 16% year-on-year. Underlying profit, excluding the timing effect of gas cost recovery was up by 19%. Our T&B businesses in India, Gujarat Gas and Mahanagar Gas continue to grow very strongly. And they posted a combined operating profit of $113 million; that’s an increase of 64%.
Now, moving from historical to the outlook, starting with the E&P segment; as you know, we plan to grow our E&P production at a compound average rate of between 6% and 8% out to 2020. However, if you look at the first five years of our plan, it becomes clear that this growth is frontend loaded. From 2010 to 2015, the compound average growth rate is 14% per annum. 2011 is a transitional year, with growth approaching the bottom end of our long-term range of 6% to 8%, and then from 2012 growth accelerates above the average rate, as new production ramps up in Brazil, Australia, and the USA. Frank will describe the projects underpinning this growth in more detail in a moment.
Our next slide summarizes the performance and the near-term outlook for the LNG segment. Over the next two years, we expect around 13 million tons per annum of LNG. And based on our current view of the market, we expect our LNG segment as a whole to deliver operating profits of between $1.9 billion and $2.2 billion for each of those years, 2011 and 2012. And, beyond this time horizon, two very important factors come into play. The first of these is a step change in our LNG volumes. Secondly, we expect the LNG supply demand balance to tighten during this period. And, Martin, will say more about that in a moment.
Our next chart shows our LNG supply plan out to 2015. The step change I referred to a minute ago starts in 2014, as the first train of LNG at QC LNG comes into production. By 2015, the second train comes into production. And our supply portfolio will then have long-term low costs supply of 20 million tons per annum. That represents a 50% increase on today’s supply levels. Now it’s also very important to remember that the QC LNG volumes have been sold on an oil index, and that means that 75% of our LNG sales will be oil related by 2015. And, if you think about the Group as a whole, around 70% of our sales will be oil or oil indexed in 2015, and that is with 50% in 2010. So an important change taking place.
In summary then, the outlook for the LNG business looks very strong indeed, a sustained and material contribution which is expected to rise sharply in 2014, as our new supply comes into production and market conditions tighten.
I’d like to now turn to our capital investment plans. Our capital spend during 2010 was $9.2 billion and this included $1.5 billion for US shale acquisitions and our new exploration activity in Tanzania. Looking ahead, we expect our capital investment to be around $10 billion this year and $11 billion in 2012. And as you would expect, that investment is focused on our large projects in Australia, Brazil, the UK, and the US.
Now, I’d like to just take a moment to compare this outlook on CapEx with the guidance that we laid out last year. Firstly, we need to rebase our previous guidance to 2011 reference conditions, and this adds about $500 million. This is almost entirely due to outpacing our exchange rates. Investments in our expanded US shale business adds a further $1.8 billion over the next two years. And, as you will see from Frank’s presentation, we expect that our US business will make an increasingly important contribution to E&P production in the years to come.
Now, turning to the balance sheet and the dividend; as I mentioned, we ended the year in sound financial position with gearing of 20%. During 2010, we entered the bond markets in UK, Europe, and the United States, and we substantially extended our debt maturity profile. At year-end, we had gross borrowings of $9.7 billion, of which, $8.4 billion is longer-term debt. To reflect our growing scale, we also increased and extended our credit lines, and we ended the year with $3.5 billion of undrawn committed facilities.
Our operating cash is healthy and it is growing strongly. We expect that this cash flow together with our strong balance sheet will enable us to fund our investment program and support a growing dividend. The Board, therefore, has recommended a 10% increase in the full-year dividend. Our dividend policy is unchanged. We aim to grow the dividend in line with long-term earnings growth.
So let me close by summarizing the key points, the Group delivered a good performance in 2010, with earnings per share up by 18%. The business is now well positioned to sustain strong growth.
Over the next five years, we plan to grow E&P production as an average compound rate of 14% per annum. Our LNG business has established on a solid foundation and it’s delivering sustained and material profits. By 2015, we expect that the LNG supply portfolio will grow by 50% from today’s levels. And in our T&D business, we’re seeing good demand recovery. And our businesses are ideally positioned to capture the demand potential which is clearly evident in both India and Brazil.
All that adds up to a very positive outlook, and that outlook is reflected in the recommended dividend.
Thank you, ladies and gentlemen. I’ll now hand you over to Martin.
Thank you, Ashley. Good afternoon, ladies and gentlemen. Now, Frank has set out our strategic framework and I’m now going to focus on the left hand side of this slide to set out our perspectives on how markets are likely to evolve.
Now, natural gas remains the focus of our portfolio, although we have a good exposure to oil. Indeed, much of our gas revenue is now oil indexed. So, I’ll begin by explaining our view of how the next decade will see a dramatic increase in gas demand that is unlikely to be met from the supply sources we see today.
So, here’s our outlook on demand across the world’s major markets. And we expect each of these regional markets to grow through 2020, with the strongest growth in Asia, led by China. We expect annual growth of 3%, and for context, the increase in demand by 2020 is equivalent to more than the entire North American gas markets today. And it’s also worth noting that almost 60% of this demand will be outside of the OECD.
Now, the market segments driving that demand are also changing and doing so in an important way. So in the past, most demand growth was driven by power generation, with gas largely substituting for coal in developed economies. In the future, we think the strongest demand growth will be driven by oil substitution in emerging economies, but mainly in the industrial, commercial and residential sectors. And this follows a well established trend in the markets of Japan, Korea and Taiwan, and would underpin gas as a premium priced oil indexed fuel over the years ahead.
Now, we think oil indexation will remains a norm for gas contracts in non-traded markets, and let me explain why. Firstly, oil is traded against deep and transparent indices on a global basis. Buyers and sellers have a broad confidence that the oil price, over the longer term, reflects the macroeconomic energy supply and demand conditions. So over many years, this transparency has given confidence to Asian LNG buyers in particular.
But, of course, oil indexation not only provides certainty for buyers, it also provides certainty for sellers in an industry where long-term costs are linked to the oil price. And our recent experience in marketing almost 10 million tons of LNG confirms that oil index station is still regarded as the norm for long-term supply contracts, and we believe this will remain the case for the foreseeable future. And, finally, we estimate that 75% of the increase in global gas will compete with, and therefore be priced against oil.
So let’s turn to our outlook for global supply. So today, this is a little over 3,000 bcma, and that’s almost a 1,000 bcma below demand expected by 2020. However, we think the supply challenge is actually much greater than this, because over the decade, many existing conventional and unconventional resources will approach end of life. And we believe this amounts to a more than a 1,000 bcma of loss production. So more than 2,000 bcma of new supply maybe required.
Now, a variety of new supply sources could fill this gap, those unconventional gas in the US. New supply is also anticipated from Russia and Central Asia and from the Middle East. And, in LNG, a number of new liquefaction facilities may come on stream potentially delivering around a 130 million tons per annum.
And, finally, we expect new supply from a variety of other sources across Asia, China, and South America. Now, if all of these were delivered on-time, they would fill the 2020 supply gap. But let’s be clear, that’s a very big “IF”. The industry would just have nine years to develop this new supply, that’s equivalent to more than three quarters of current supply levels, just to meet the expected demand growth.
Supply would need to grow at 9% a year. A huge endeavor representing investments of some $2 trillion as average industry F&D costs. So if we take all this and put it into context and take Norway as an example, the industry has less than nine years to develop and bring on stream the equivalents of 20 times the total current gas production of Norway, and this is just to meet current demand projections.
So not only do we see a strong outlook for demand growth, we also see a huge corresponding supply challenge, and any significant supply shortfall would tighten gas and LNG prices considerably. In turn, of course, that would benefit companies like BG Group with material new supply projects already underway and a strong low-cost reserves and resources position.
So now let’s look at the three key regions beginning with the US. So we expect modest demand growth in the world’s largest gas market. The US has abundant shale gas resources that have transformed domestic supply outlook. So we expect gas prices to remain well below oil parity for some time. That should have positive demand implications with increased scope for competition with other fuels in power generation, oil feedstock industries, and transport.
In Europe, we expect gas prices to remain much closer to oil prices than in the US. We expect demand growth will be driven by continued economic expansion with indigenous supply declining as major existing fields reach end of life. So significant increases in pipe gas and LNG imports will be needed. So we think Europe will remain an attractive high-value market, with gas at the heart of the energy mix. And we think prices will remain strong to stimulate the necessary investments in new pipelines and LNG imports.
Turning now to Asia, we expect these gas markets to demonstrate the strongest growth over the next decade. Oil substitution and high economic growth should drive strong demand growth in the industrial, commercial, and residential segments. Although, we expect indigenous supply sources to increase, we think that LNG imports will play a key role in the supply mix. We believe that these will rise sharply through the decade, with oil index pricing continuing incentivize new long-term supply.
Now, the key market here is China, where gas currently accounts for less than 4% of the energy mix, much lower than in comparable economies. An increase of just 1% in gas penetration, adds around 25 bcma to current Chinese gas demand. That’s the equivalent to the total output from four additional trains at QC LNG in Australia. Now, if gas penetration in gas were to rise to the level in India, which is already still very low by global standards, this alone would result in an increase in Chinese gas demand of around 150 bcma, and that’s the equivalents of around 100 million tons per annum of LNG. In other words, around 1.5 times the current total capacity of Qatar.
In fact, forecasters generally underestimate Chinese LNG demand by a significant market. So three years out, this was the forecast LNG demand curve out to 2020, a path of steadily rising demand to around 14 million tons per annum. A year later, that curve was revised sharply upwards and it increased further again in late 2009, to reach today’s forecast level of 45 million tons per annum by 2020, a three-fold increase in just three years. And to compare this with the contractual reality, 2020 volumes committed all under negotiation our approaching levels we estimated in 2009. We also believe a further 12 million tons could come under contract in the future, which would then approach the most recent estimates. And, finally, the amounts of re-gas capacity already proposed foreshadows a further demand increase.
And, meanwhile, the consensus 2020 forecast for global LNG demand is around 350 million tons per annum. This is a view of trade. In other words, the portion of demand that is likely to be met with new supply. However, it is not an accurate assessment of absolutely demand. In fact, it doesn’t represent the true supply demand outlook at all, and here’s why.
So current and sanctioned LNG supply is about 280 million tons per annum, which leaves a supply gap of around 70 million tons. So the industry would have to sanction the equivalent of a Gorgon projects, every year for the next five years just to close this gap. And, of course, that’s quite a challenge by historic benchmarks.
Now, if we look on the demand side, we believe this will be much higher than the 350 million tons. We’re seeing latent LNG demand in economies such as China and India. And there’s also a large number of new markets such as Argentina, Brazil, Kuwait, Cyprus, and even Saudi Arabia, now looking to import LNG. So we expect underlying demand will be well above 350 million tons per annum. In addition, supply is unlikely to meet forecast levels, let alone the true level of demand. So in our view, it is supply and not demand which will continue to constrain the size of the LNG markets, leading to an inevitable supply tightens.
So I now want to turn to our distinctive LNG business. Now this is underpinned by the reality that there is not one single global gas markets. Instead, there were many local and regional gas markets, each with different characteristics, and we capture value from both robustly profitable underlying trades and for markets in perfections using a new array of assets, skills, our low cost LNG supply, and an extensive network of customers.
Now, traditionally, LNG plays build by businesses upon long-term point-to-point bilateral arrangements with inflexible take or pay contracts. These brought together new customers and new supply sources. And whilst these type of contract does have a place in our growing portfolio, it takes time to achieve the perfect alignment of customers and suppliers. So these arrangements often lead to lengthy development timeframes.
By contrast, we have a flexible portfolio of both equity and third party LNG supply. And this is facilitated by our terminal capacity, by our shipping fleet, and by the scale and liquidity of the US market. So taken together, these provide a flexible, risk mitigation alternative to long term by natural contracts. And, in turn, this flexibility has enabled us to establish a diverse set of customer relationships. Our ability to tail a supply to customer needs free from project-specific constraints and delivery timing has been a key to our marketing success in the Asia-Pacific region over the past two years.
So we work with multiple customer and supply propositions in parallel. It’s a virtual circle of markets then supply or supply then markets, with optimization at each step. Today, our LNG business is sophisticated, fully globalized and highly valuable. And we are relentless in our pursuit of optimization and value accretion.
We purchased cargos from 12 as of 18 LNG supplying countries and have sold to all but one of the 23 LNG importing nations. And this is a model built on our distinctive sources of competitive advantage; it’s an approach which makes the space to satisfy the needs of both sides and seeks to eliminate risk and project delay, improving the value proposition overall. And it’s a strategy which broke the LNG paradigm which is easy to understand than it is emulate.
So let me give you two examples of this strategy in action. On the market side, we’re working with the Energy Markets Authority in Singapore to build a downstream customer base which will be supplied from our LNG portfolio through the new Singaporean LNG terminal. In just 10 months, we’ve built 2.2 million tons per annum of new LNG demand from seven customers.
Meanwhile, on the supply side, we knew we wanted more oil indexation in our portfolio, so we set about turning out some of our Atlantic basin volumes to Asian customers, helped by the work in pre-building these markets, we were then able to realize a long-term strategic goal, establishing an equity specific base in supply source through our activities in Australia. This allowed us to develop the QC LNG project rapidly and ahead of competitors. Now, our portfolio approach also allowed us to market freely unconstrained by concerns about project timing and pricing.
So as we look ahead to 2020, we anticipate strong growth in our LNG volumes. We now have around 13 million tons per annum of LNG supply. We’ve increased our LNG profit guidance to between $1.9 billion to $2.2 billion per annum out to 2012. By 2015, we expect this volume to increase by about 50% to some 20 million tons per annum, driving a step change in LNG profits. Finally, given the rapid progress at QC LNG, the growth potential within our portfolio and our exploration success, we’re now modeling a supply potential of 30 million tons per annum by 2020, a further 50% increase.
Ladies and gentlemen, we sometimes hear that the world is a wash with gas and LNG, now and into the future. We just do not agree with those views. Instead, we expect strong growth in global gas demand through the decade with supply struggling to keep pace. We expect global LNG to grow sharply constrained by supply not demand, and with oil indexation as the established norm. And we believe we’re well positioned to take advantage of these opportunities with a distinctive array of assets, skills, customer relationships and a highly profitable LNG business that today is easier to understand than it is to replicate.
Ladies and gentlemen, let me now pass you on to Frank, and thank you for your attention.
Thank you, Martin, for providing some insights into our market focused approach. I now want to turn to the right hand side of this picture, beginning with a continuation of the LNG story.
And we sanctioned the 8.5 million tons per annum QC LNG project on the 31st of October last year. This achievement is only 34 months after entering Australia, represents a realization – the realization of a key long-term strategic objective being to globalize our LNG business through acquisitions of Asia-Pacific equity LNG, providing them a bridgehead to supply new oil indexed regional customers.
We’re investing around $15 billion in the initial two train development, with Asia-Pacific customer agreements, now almost at 10 million tons per annum. We plan to complete more than 2,000 wells by 2014, rising to more than 6,000 wells over the life of the project. Connecting the field to the LNG plant will be a 540 kilometer pipeline network. Construction on Curtis Island is gathering pace. These will be the seventh and eighth LNG trains that we’ve built in the last 12 years using the same contractor and the same liquefaction process.
And there is expansion potential beyond the first two trains. In the upstream we’ve made good progress, expanding and maturing the resources’ position. Gross resources have increased from around 5 trillion cubic feet when we first acquired an interest in QGC to 21 trillion cubic feet today, so four times the level at play entry just three years ago. At the same time, we’ve increased 2P reserves six-fold to 8 trillion cubic feet. So a rapidly evolving and maturing resources picture which together with third-party gas opportunities supports our efforts towards sanction of a third train.
In the midstream, our infrastructure is already scaled to support three trains with only modest additions to the facilities. The Curtis Island site is permitted for three trains and has space for up to five trains, giving a potential of some 20 million tons per annum.
Leveraging existing infrastructure would offer enhanced economics for a third train with significantly lower unit CapEx for the plant and the midstream, and we’ve already begun marketing train three, and are confident that we can secure further sales.
Finally, here is the production outlook for Australia. As a result of all of this progress, we’re now well on our way to realizing net production of more than 210,000 boe per day from the first two trains.
I’d now like to turn to another of our major growth projects, our US shale gas business. The contribution from shale to US and Canadian gas production is expected to more than double from 20 billion cubic feet to 50 billion cubic feet per day over the years to 2020, at which point, it will account for more than half of total production. When considering the opportunities for value creation that flow from that structural changes. Important to remember that methane as the basic commodity is undifferentiated, costly to ship, is therefore, the only sustainable competitive strategy. Commercial success depends on access to the most prolific resources, combined with competitive cost performance.
Over the last 16 months, we have assembled a high-quality low-cost resource base, totaling 8.5 trillion cubic feet, around 1.4 billion boe, and offering economic breakeven at prices well below current forecasts. In 2009, we acquired some 3.2 tcf of reserves and resources at a cost of around $0.40 per 1,000 cubic feet. We have since increased this resource base by more than 60% to 5.3 trillion cubic feet. We plan to drill around 675 Haynesville wells between 2011 and 2020, with 80% of our Haynesville production over the next five years sourced from the highest quality De Soto and Shelby core areas.
During 2010, the number of rigs operating grew from 14 to 23. And we now have more than 125 horizontal wells in operation, many of which have achieved initial flow rates of more than 20 million cubic feet per day. As a consequence, BG Group ended the year having increased net production by around 300%.
We now have around two years of production experience from 90 wells, giving us a fairly extensive dataset, well performances consistent with our assumptions, providing confidence in the sustainability and economics of the play. We expect each Haynesville core well to product on average around 9 bcf, achieving 40% of this total in the first two years. And we expect to drill around 275 of these wells in this play within the next five years.
Anticipated CapEx is $9 million per well, that’s around $1 per million Btus, with ongoing OpEx around $1.40. And this gives us a unit technical cost of around $2.40 from field through to trunk line. Of course, capital efficiency is high given the very short lead time from capital expenditure through to first revenues. And consequently, economic breakeven can be achieved at gas prices down to $3.20 per million Btus, making these projects look very favorable at current forward price assumptions.
The Haynesville marked our entry into US shale gas and we’re now applying the experienced gained to as yet less mature, but very expensive Marcellus play. Here, we acquired 2.9 tcf of resources at an average cost of $0.40 per mcf. With two rigs operating, we now have 12 production wells in the area and we expect this to grow to 50 development wells and 10 appraisal wells as we ramp up to five rigs during 2011. It is, of course, still early days in the Marcellus, however, we believe this play has the potential to demonstrate similar core area economics to our Haynesville acreage.
Now, alongside our production assets in the Haynesville, we also have a growing midstream joint venture. This provides us with a distinctive advantage over our competitors, we’re able to execute our developments without dependence on third-party transmission enabling us to play independently and to capture market opportunities.
Our midstream JV operates around 1,000 miles of pipeline, volumes gathered and treated are expected to increase by more than 30% per annum out to 2014 to reach more than 3 bcf per day. These are, of course, great assets to own at this formative stage of the industry. They represent material, embedded value that will grow rapidly as the network is expanded in the coming years.
So turning out to the production outlook in the US, we expect to sustain net Haynesville production at around 100,000 boe per day to 2020. When we add to that the Marcellus, this brings the net total to a 190,000 boe per day by 2015, almost double the level we announced at last year’s presentation. And there is potential raise this, still further to above 200,000 boe per day. And for context, this, of course, would make the US almost as great in production terms as current plans for Australia.
So we now have a rapidly expanding and capital efficient shale gas business with total resources of 8.5 tcf. Moreover, this business leverages the existing US marketing capabilities and is very strongly positioned to benefit from the ongoing supply restructuring in the world’s largest and most liquid gas market.
Now, let’s turn to Brazil. 2010 saw very significant progress with our Santos Basin interests. We upgraded Lula. The resources at Lula, Cernambi, and Guará, we issued guidance indicating low unit technical costs for the first three FPSOs. We commenced production from the first permanent FPSO on Lula and we progressed the contracting of a further 12 FPSOs.
All of this has helped to de-risk the development sequence, the schedule and the project cost, and greatly enhances the visibility of this high-value play, a play where the consortium signaled its confidence through the commitment of some $13 billion during 2010. And the rapid progress is testament to the commitment and expertise of the operator, Petrobras, but also to the excellent collaborative relationships within our two consortia as we work together to deliver this outstanding growth program.
We expect the first three FPSOs on Lula and Guará to recover around 750 million boe per module, more or less double our original estimates, and we anticipate capital costs of around $5 per boe and OpEx of around $9 per boe. We also expect to access a Brent parity pricing for this sweet crude at a transportation cost of $4 a barrel. Now, these parameters underpin attractive economics for these first three units, and this will be a key building block in estimating the value to be derived from subsequent developments.
You’ll have seen our certified resources upgrade on Lula and Cernambi, details of which are included in your handouts. We estimate gross reserves of between $7 billion and $11 boe, with the $9 billion midpoint around 40% higher than previous indications. Note that these are BG Group’s current estimates. In our view, they do not yet represent the full potential that may be accessed in future through the deployment of enhanced recovery techniques and later phases of in-field drilling. Furthermore, our continued drilling and testing of delineation wells at the field extremities is expected to improve current downside estimates.
On Guará, our certified gross resources upgrade narrowed the range to between 1.5 billion boe and 2 billion boe, and the consortium now plans to deploy two FPSOs on this development. This year will refine our understandings through an extended well test already underway and presently producing around 20,000 barrels per day constrained by the EWT facilities.
Turning now to Iara and Carioca, last year we spudded the Iara Horst appraisal well, on which we will conduct a DST this year. Future plans include a third appraisal well and an extended well test next year. Last month, we reported yet another discovery well on Carioca Northeast, which encountered light oil in a 200-meter thick reservoir section, a stem test will follow on this well quite shortly. We’ll also drill the Carioca Sela appraisal well later this year, and we’ll conduct an extended well test there.
Associated with these oil discoveries, our material gas resource is currently estimated at more than 14 tcf and located within easy reach of downstream market served by our own Comgás business. During the year, we installed a new pipeline connecting the Lula field through to the Mexilhao gas hub, and we are preparing to tieback the first FPSO. This pipeline has capacity for the first three FPSOs with further pipelines being planned for 2014. Also, in 2010, we completed frontend engineering and design studies for floating LNG, and expect to conclude our analysis later this year.
So momentum continues to build across the Santos base, and let’s take a look at our plans for FPSO deployment. The first module is already on stream on the Lula field. 2013, sees the second FPSO on Lula and the first on Guará. In 2014, we add a second FPSO on Guará and deploy the first on Cernambi. These are the FPSOs currently in the process of tendering.
From 2015 to 2017, we plan to deploy eight more FPSOs and these have been committed to Lula, Cernambi, Iara and Carioca. So gross production capacity of around 2.3 million boe per day and all of it expected on stream by 2017. We are in fact close to the inflection point in our Santos Basin developments with on average more than 300,000 boe per day new capacity to be added every year for the next seven years.
So based on the consortium’s current agreed 13 FPSO program, BG Group estimates that this scheduled capacity is already more than sufficient to deliver our net production guidance stated last year. However, there is much work ahead before the joint venture finalizes field development plants. In the meantime, it is BG Group’s view consistent with our latest reserves and resources estimates that we can anticipate further progress. We believe that these fields will in time be shown to be of a quality and the scale, sufficient to support net production above 550,000 boe per day by 2020.
Let’s turn now to exploration progress and our resources base. First, a little context on our exploration track record. Since 1997, we’ve participated in the discovery of 13 giant fields at [inaudible], Buzzard, Carioca, Cernambi, Guará, Iara, Kalamkas, Moray, Kashagan, Lula, Margarita, Scarab, Saffron, Simian, and Porvata [ph] Tangu. At the same time, our total resources base has grown from 3.6 billion boe to 16.2 billion boe, after some 2.5 billion boe of production. Underlying these statistics is a 14 billion boe of organic growth, on average 1 billion boe of resources added every year for the last 14 years. I think, therefore, it is fair to say the BG Group is one of the global leaders in exploration among our top 30 peers.
Here are a few independent statistics supporting that view from Wood Mackenzie, which for example, over the last 10 years, places BG Group in the top three for achieving high rates of return from exploration, shows a sustained 400% reserves replacement rate by exploration and an average discovery cost of just $0.71 per boe, making BG Group one of the most efficient explorers in our industry. And when one considers the scale of the value created in Brazil, in Egypt, in Kazakhstan, Trinidad, the UK, and now most recently in Australia and in the US, it is clear our exploration activity has added and continues to add very material value indeed to the investment proposition.
We’ve grown our inventory by about 12% per annum over the last 10 years to reach today’s 3.7 billion boe of net risk resources. Our opportunity set is diverse spread across more than 200 prospects and leads. There is a good balance between play types and around 85% of these resources are gas related, more than 60% are in locations where we have established production, and more than 70% are in investment grade countries. Importantly, the gross un-risked resources within this inventory amounts to around 47 billion boe, 19 billion boe of which is net to BG Group. Now, when you consider that we operate from than 70% of this inventory, it is clear that we are in control of significant resource potential with scope for material new core ventures in Australia, in China, Egypt, Norway, Tanzania, and of course in the US.
And, in 2011, we will be drilling out opportunities in all of these countries, as shown here on the chart. This includes a number of important new play openers, but I’d also like to highlight our focus on appraisal, ahead of near-term production, particularly once again in Brazil.
Two areas where we have had recent success is our China and Tanzania. The Mafia Deep Offshore Basin and the Northern portion of the Ruvuma Basin are frontier place where we have an excellent acreage position, amounting to some 28,000 square kilometers, that’s equivalent to around 140 UK blocks. Our first two wells are significant gas discoveries in high-quality reservoirs, and these of course, are encouraging. Early indications from an area with a wide range of play concepts to the explored.
Tanzania is also another illustration of our market focus strategy with the country favorably located to supply growing LNG markets in the Eastern Hemisphere. The next step is going to be to test potential prospects in block one, with a focus on aggregating sufficient quantities of gas in near just opposed discoveries, and we look forward to sharing further progress with you in due course.
There are also encouraging signs – early signs from our first drilling offshore China, as the Lingshui well encountered high-quality gas-bearing sands in the deepwater Qiongdongnan Basin. Here too, we have a good acreage position, with licenses in three blocks spanning 15,000 square kilometers. We are currently drilling a second well and plan to acquire some 1,500 square kilometers of 3D seismic. Now, as I mentioned in my opening, during 2010, our total reserves and resources increased by some 1.7 billion boe. These now stand at around 16.2 billion boe, up 12% year-on-year, and now providing some 69 years of production at 2010 levels.
Our total reserves and resources had grown by more than 8 billion boe over just the last four years, a compound growth rate of 19% per annum. I would also highlight our 2P reserves replacement rate of around 350%, and this supports, of course, our confidence in consistently strong 1P reserves replacement over the years ahead as we progress our major growth projects.
Now, the delivery of that growth begins with the addition of large volumes from Brazil, then comes the contribution from Australia, here based on the current two train base case, followed by increase in production from the US. And, finally, we have production from our other assets. You’ll see that these take us already to the midpoint of the long-term 6% to 8% growth range. This now achievable from reserves and resources already discovered in our portfolio. Then, we have the risk resources from our exploration portfolio, which we believe will allow the top end of this range to be reached or exceeded.
Now, here’s an overview of the key projects that will contribute to that growth profile. Details of these projects are included in your handouts, and this includes the major projects which we’ve discussed already today, together with important projects in Bolivia, in Kazakhstan, Norway, Trinidad, Thailand, of course the UK, all of which are currently included in our business plans.
So to conclude, here is the summary of our progress over the last 12 months. E&P; growth range of 6% to 8% to 2020 reaffirmed, the 7% midpoint achievable from existing discoveries. LNG; our goal of 20 million ton supply to 2015, reaffirmed with 30 million tons supply potential, and we’ve also increased, of course, our LNG profit guidance.
Brazil; we now believe net production could exceed 550,000 boe per day by 2020. QC LNG; sanctioned and progressing towards more than 210,000 boe per day from the first two trains. US shale gas; expected 2015 production almost doubled now to 190,000 boe per day. And, finally total reserves and resources, up 1.7 billion boe.
So I hope, today, we’ve given you some new insights into the strength and depths of our growth plans, the real momentum that is now building and the shareholder value proposition. But more than this, I hope today has also served as a reminder of the strength that we continue to draw from the pursuit of a clear strategy. It’s a strategy that has over the years enabled us to assemble an array of competitive advantages which we can continue to leverage to win new opportunities, so sustaining our business and sustaining the creation of long-term value for our shareholders.
Thank you very much for your attention. In a moment, Ashley, Martin and I, will be happy to take your questions. Before we do that, a few words about Ashley has – it’s already been mentioned that this is his last strategy presentation and results announcement, and he will be standing down from the Board at the end of March. I would like to express my gratitude to Ashley for the enormous contribution he has made to BG Group over the years.
He has worked with me closely in what I have described as an exceptional partnership and quite a lot of what you see today in the Group has been the result of some tremendous collaboration. And, although Ashley is going to be with us still for a little while, of course, I’m sure you all want to join me and wishing him every success in what he chooses to do hereafter.
His successor, Fabio Barbosa, sitting here in the front row, I mean enormously experienced in all matters, Brazilian, but also much more broadly with his financial background and his knowledge of extractive industries, I look forward enormously to working with you, Fabio, as we progress the delivery of what I think is a very exciting program that we have laid out in front.
So thank you very much, ladies and gentlemen, for your attention. And, Ashley, Martin and I, will be delighted now to take your questions. Thank you very much.
I think those are vodka, those ones over there, I’m not sure. Okay. Who is going to be first? Microphone over there, thank you.
Christine Tiscareno – S&P Equity Research
Thank you. Christine Tiscareno from S&P Equity Research. Could you just give us an update of what is happening in Kazakhstan and what do you think might happen in Egypt? I know operation you haven’t been affected, but could you give us your thought as to what would happen with the change in the regime? Thank you.
Well, let me just – Ashley is going to take Kazakhstan. But let me just take the situation in Egypt. You’re quite right in saying that our production operations haven’t been particularly affected there. We have had some interference with new development work that we’re doing on phases 7 and 8a, and we’ve had some interference with our drilling activities related to the same projects, because of essentially logistical problems. And, but those appear now already to being returning to normal.
Drilling is – drilling crews are arriving back and they’re starting to get those activities going again. I mean, I don’t really want to speculate on what’s going to happen in country; that is really a matter for the Egyptian people. What I do know is that we’re together with our partners, have spent as in many of these places, quite a lot of money, about $10 billion over the years in developing the gas industry. It’s made a huge impact on the local economy, create lot of value, lot of jobs. If you look at gas demand the way it’s developed in the residential, commercial, industrial power generation segments, all of these are up, and that is of course a good indication of the contribution.
There is still, of course, a huge amount to be done in Nile Delta, in terms of development of existing resources and further exploration work. And if feel sure that whatever political persuasion eventually comes into power in Egypt, then that government and the people of Egypt will want to see a continuation of the contribution that companies like BG are making to the development of their economy. So troubled times, but I feel that, given that what we’re doing in the country, we will in time come through this.
Christine, on Karachaganak, we together with our consortium partners are meeting regularly with the government. The dialog is very constructive. I’m increasingly confident that we will find a mutually satisfactory solution to these discussions. And, I think that dialog is also reflected in the operating environment, which is now very positive; the working relationship on a day-to-day basis, between the consortium and the republic has now made a good footing. So I think it’s right for everybody to, us, particularly, to work through this patiently, and if we do that we’re confident that we’ll come up with a good plan for the future development to the field.
Next question, please.
Jason Gammel – Macquarie
Thank you. Jason Gammel with Macquarie. I was hoping that you could comment on the incremental sources of supply, I think you did 30 million ton per annum LNG case, and would be particularly interested in comments surrounding Tanzania and floating LNG in Brazil that would potentially play into that.
Of course, the first thing that comes to mind, of course is train three – QC LNG and the prospective to support that. I mean, if today, if I’m talking 21 tcf of total resource base, that includes risked exploration – and the risking factors are slightly different in unconventional bases, but risked exploration, discovered resources which are under evaluation, discovered resources which are pending development, and then your sort of probable reserves and probed reserves, you got that whole stack. 21 tcf is the total, that’s already enough really more or less of three trains.
But, of course, we’re not committing to train three right now, because there is process of needing to promote those various resource categories into the proved and probable part of the table, such that, you have really confidence about your first two trains before you start, promoting train three. I mean, train three, our deadline ideally, we’d like to sanction at 18 – within 18 months of the sanction of the first two trains in order to get construction continuity. So the game is on in terms of conducting appraisal drilling – exploration appraisal drilling in order to try to prove up reserves in that sort of timeframe.
Beyond that, we have a number of opportunities. You mentioned one of them, which is Tanzania, but there are also other things that we are doing. For example, debottlenecking processes, what’s going on Trinidad; we’ve got the floating LNG thing in Brazil, with a lot of gas potential behind that; and there are some other things which we’re not discussing. But amongst all of this, is there a case for 13 million tons? Absolutely, you put all these together. I mean you can get to 30 million tons from two trains from somewhere, and train three, I mean you’re there.
Tanzania, well, I’ve mentioned that there are encouraging signs. It’s always nice to going to a virgin basin and drill two wells, and have two very nice discoveries in very productive sense and reservoirs. This is good sign, and we’re on with the program there.
So – is that enough of a picture for you? That will do for moment. Let’s move the questioning over to this side of the room, if we can, please.
Jason Kenney – ING
Hi Frank. It’s Jason Kenney from ING.
Jason Kenney – ING
So a couple of questions, if I can. Now, the global gas market is going to remain tight according to Martin, and your LNG volumes are projected to increase, and yet you’re envisaging a decline in LNG profits over the next two years versus the last two years, so are you just being over conservative on the 1.9 to 2.2?
Our FD here will tell me, it’s 1.9 to 2.2, that’s our guidance. The market will, of course, be getting a little bit of an idea about how this business has performed. So we thought we would leave you a bit of a puzzle for 2013 and onwards, to try and figure out what you think is going to happen with this business. But, no, I don’t think we’re being overly conservative, we’re giving you what we believe is a realistic outlook.
We are, of course, quite confident, we’re not giving you how much is sold, how much is hedged and all of that, we’re just giving you some guidance on profitability, and we are confident that we will be able to deliver within that range. Ashley, do you want to add anything to that?
Yes. The only thing I’d say, Jason, is you’ll have noted in my comment about good weather-related demand in 2010. So that was clearly a little bit of a windfall for us. But, yes, I’d agree we’re not being deliberately conservative. The volume increase that you refer to comes in 2014 to 2015, so I think in broad terms the picture is steady as she goes till 2014, and then we expect it to kick up.
Jason Kenney – ING
Can I ask a follow-up question as well, while I’ve got the microphone? So – I can understand the very strong focus on LNG, and obviously the optimism from 30 million tons per annum. I’m just wondering how you’re going to fund that kind of investment further out and could you envisage a slowdown at Brazil in the medium term in order to redirect and rebalance yourself back to your core skill, which is the integrated guess?
Again, you have to look at timing, and the third train of QC LNG. And beyond that, the 30 million ton case is further out in this decade. So I think that for the meantime, there are two things happening here, you’ve got obviously high levels of investment going into projects over the next few years, but along side that and simultaneously, you’ve got new projects coming into production, which are going to make an increasingly large contribution operating cash flow. And, once we’re through 2013, 2014, I think that the weight of cash flow from those new projects, you have to make your own assumptions about prices and exchange rate, but the weight of that cash flow should be more than adequate.
Can I just comment on the business about us getting back to our knitting? You mentioned, I mean, let’s understand clearly, when we drill a well we have an idea about whether it’s an oil-prone well or a gas-prone well. 85% or 80% or so of our exploration portfolio is gas-prone, but it doesn’t mean to say it’s all going to be gas. We don’t know that until we drill these wells. And we, of course, are operating in deepwater drilling wells, building platforms, conducting production operations and so on. These skills are common to oil production and gas production. And at the lowest level, we take skills and we apply them to opportunities in order to create shareholder value. We are not going to get caught in a strategic cul-de-sac where we say, “Unless it’s gas, we won’t do anything with it.” If we discover oil, we sell it to somebody. I think that is a flawed piece of thinking.
We have been very clear about our gas strategy, very strongly growing gas demand, increasing oil indexation in that gas demand, a special set of skills to connect long-term sustainable economic resources to target markets, all of that has worked enormously well for us and sits behind much of the growth that we’ve seen. But please don’t misunderstand that that means if we discover oil and it’s very valuable, we’ll sell it.
We want to create value for our shareholders and we will pursue any route to do that. I do still think that if you rollout to 2015 to 2020, you will still see as is the case in our plants today, more than 50% of the business being gas, okay? So, I’m very pleased to say that on value that the market is just beginning to see the visibility of everything we’re doing in Brazil, right? And it’s that visibility, I think, which is starting to peak prompt new evaluations and new assessments of what we’re doing there, and I feel confident that that is going to continue as people gain a better understanding of the real momentum that is growing. I’m sorry I’ve taken a lot of time. Orally [ph], a gas is not a dogma. Irene?
Irene Himona – Societe Generale
Thank you. It’s Irene Himona with Societe Generale. Two questions, please. First, one for Martin, you make a convincing case about the tightening LNG market to 2020. But, obviously near term, we have had quite a major dislocation caused by the shale gas in the US on the supply side, and of course the economic crisis on demand. Can you indicate approximately, at what point time, we should expect to see the market begin to tighten. Is it next year or two, is it middle of the decade?
Look, I think it’s – everybody has got a different number for this one, and my number may not be much better than yours. What I would say is that there is a large gap that’s opening up and we did have a situation where the people expected last year to be a wash with LNG as 40 million tons, 22% of supply came on stream in one year. And, actually what happened, if you use the US as a barometer for imported – barometer if you like in surplus LNG and the system, if you like, it didn’t change. Actually what happened was, a lot of markets absorbed much, much more LNG in Korea, Japan, China, UK, Italy, and there are very significant changes in the demand profile, and also of course new markets emerged as well. We’re seeing significant demand in South America. I mean, cargos to Brazil, Chile.
40 cargos went to South America.
40 cargos in South America. The Middle East; the Middle East is a growing – fast growing market. As I said, the Saudi Arabia potentially as an importer. So it’s not always what it seems. And we’ve already blown through that, and it’s going to be very interesting to see what happens in 2011.
Irene Himona – Societe Generale
Thank you. My second question was, if you could just brief discuss cost inflation pressures in particularly Australia and Brazil. Thank you.
As I said in my remarks, the – for the portfolio as a whole, we see 5% to 10% cost inflation certainly in operating costs. That’s obviously sensitive to the price environment. We all know that prices and costs go together. And if we see sustained oil prices above $100 a barrel, then I suspect we’ll see certainly inflation to the upper end of that, possibly a bit more.
In Australia, I think what we’ve tried to, and Martin can certainly talk as an expert on this, since he was closely involved with Cath Tanna down in Australia, but what we’ve tried to do Irene is to get in front and to secure our major contracts, main work contracts in the upstream, in the midstream, and also to enter into labor agreements, which we’ve done now.
So nobody can claim to be immune, and of course we recognize that particularly in the area of civil works is going to be more demand for that sort of supply factor in the next 12 months. But I think we’ve put ourselves in the best possible position in Australia to deal with that risk. It would be a mistake for us to think that that job was finished. We have to continue to manage them closely. And, maybe on Brazil, Frank or Martin wants to take that.
Well, I just want to say some more about this, issue about skill shortage, following the flooding and disaster downtown in Queensland. Very much welcome the Federal Government’s declaration that they will expedite temporary work permits skilled labor coming in to help with the recovery. I think that will make a huge difference to the availability of skilled labor, particularly as Ashley mentions in the civil engineering, we talk about road and rail, essentially civil engineering disciplines.
Brazil; I’m sorry, I’ve lost the Brazil question.
Question, inflation in Brazil.
The only thing I would add on the Australia is, I think it’s an important point that Frank touched on, which is the labor agreement. So – and if you think about labor as being something we’ll often see quoted as being a risk to delivery. And, particularly with the recovery work, of course, has now go to go on in the civil area within Queensland itself post flooding. I mean, we’ve got labor agreements that run to the end of 2014, which gives us quite a lot of security in terms of what the picture looks like for us going forward.
Thank you. Fred, we’ll take your question. We’ve got microphone. Irene, can you pass along?
Irene Himona – Societe Generale
Fred Lucas – JP Morgan
Thanks very much. Fred Lucas, JP Morgan. Couple of questions – actually three, if I’m honest. I take everything you say about the sustainability of oil price indexation, but why are you so confident that governments aren’t going to clamp down on the tax leakage that occurs, whereby the gas leaves their country at a much higher price, exempt from an upstream tax rate fence. So why won’t that oil price indexation get pulled out to the well head by governments?
The second question I have is regarding the US gas shale. There is – normal companies are firming up capital commitments to US liquefaction, source from the US gas shale. I’m just surprised and looking as to why that’s not a feature of your strategy today?
Fred Lucas – JP Morgan
And, a third quickie, if I may. Given events in Egypt and disruptions to gas supply from Egypt to Israel, 10 years ago you discovered around 1 tcf of gas offshore Gaza. I wonder do you still have title to that and could the situation actually unlock that piece of stranded gas?
Pardon. You take tax, okay? You can take US shale gas and I’ll deal with the Gaza, okay? Off you go.
Organize these boys.
Taxation; again, we would be foolish to be complacent about fiscal creep. But what I would say is that, if you think about the production centers that put LNG into our portfolio, in all cases, the export agreements around those facilities have been put together at the same time as the upstream.
In other words, this is – the export is being contemplated at the time that the upstream has been developed. And, consequently, there are arrangements in place, whereby some of the rent in the downstream does netback in to the upstream. So I think that we would – we would simply point out that, what’s happening today is nothing something that was not contemplated at all when these agreements were put in place. And, secondly, the rent that accrues to the governments in all of these countries is pretty material.
Yes. I mean, Fred, on exports, we obviously – I’m not quite sure that a lot of capital commitments have been made as you put it. I think a lot of people talked about making capital commitments, whether they do is not a matter. I mean, first of all, there is a lot of unsatisfied LNG demand, I think if you look at slide 40 and take the arguments that we made. And into that, of course, exports from the US are not going to make a radical difference.
The question you asked was would we – does it feature in our future plans? I mean, let’s just say one or two things about it. Massive capital investments are required in there, so that capital has got to work long term. It’s got to satisfy long-term buyer needs and long-term seller needs; the latter being more difficult to contemplate from a commercial structure’s point of view.
So if you’re talking about the price of the day, the seller wants the best price on the day, maybe oils today, but it maybe gas in the US, who knows in the future. So the commercial arrangements are not out straightforward. And there are some US policy issues, there are some US sentiments issues that have be to managed as well.
All of that said to answer your question on the nose, I mean have we looked at it? Yes, we have looked at it. We’ve taken a very hard look at it. We’ve – I think a very good understanding of what the economics look like. And we’re looking at it, to see whether it should feature in the future in our business.
I mean, they may end up being some LNG flowing from shale gas somewhere into the LNG market as Martin said. The latent demand for LNG is in our view so great it’s not ready likely to influence materially that picture over the timeframe that we’ve considered here.
Gaza; yes, we still do own the rights to the Gaza gas discovery. You’ve seen the progress with – or ideas flowing from Blair-Netanyahu conversations. I mean I would say that those are encouraging signs, but they are a long way from providing a comprehensive framework and a comprehensive set of bilateral agreements that would enable a material investment to go ahead.
So for the moment, we’re engaged and we’re listening to what’s going on. We’re not engaged with the Israelis, we are, of course, as a license holder engaged with the Palestinian authority, but I think my feeling is that you shouldn’t hold your breath on this one, there is some distance to travel. But we still have the rights.
Hootan Yazhari – Bank of America Merrill Lynch
Hootan Yazhari from Bank of America Merrill Lynch. Two quick questions. Firstly, in Brazil, you very kindly in December offered some guidance on the cost structure that we’re looking out, out there. Obviously the first three FPSOs we’re looking at are on the smaller side, 120,000 barrels a day roughly on average. The latter FPSOs you’re bringing on looked to be of a 150,000 barrels a day. Can you give us some sort of guidance on the sort of cost savings, economies of scale we could expect there, and sort of recoverability per FPSO we’re looking at? You’re guiding it to 750 million for the first three, so I would imagine the next phase is going to be substantially larger than that.
And then, the second question, a bit simpler – you’ve accelerated Brazil, you’ve accelerated the United States, yet you’ve kept your production guidance at 6% to 8%, alluding to the fact that you could support 7% with your underlying current resources. What would it take for you to move that? And, even if you look at slide 10, it looks like –even the 8% looks very light. What am I missing something here?
We’re in a position and we have been in a position of saying, “We’re not going to change every year our production guidance.” This is not really about what we’re going to produce in quarter one or quarter two, this is about our long-term growth program. And, we’ve given, if you like, a range of 6% to 8%. And we tried diligently not to touch that. I mean, we haven’t adjusted that for the last six years. Well, yes, I mean for sometime in any event, and it’s our intention to stay there.
What, of course, happens is when you stand 15 years before our projected future, quite a large proportion of what you project is made up of expectations of resources and ventures that will flow from risked exploration activity and it’s a bit like moving resources down into higher levels of confidence.
What we’re doing, as we move forward in time is actually promoting the confidence level that we can get to those growth rates rather than adding more growth rate on top. I mean if you reset the growth horizon to 2025, then maybe you might do that, you might change these numbers up or down as you start to make allowances for expected exploration performance in as you move further forward. But as we move towards 2020, you see that that risked exploration which gets smaller and smaller – we took 200,000 barrels a day in 2020 out of the exploration category in one year, that’s good progress. So that’s what you will see, you won’t see the targets moving so much, but you will see a confidence level increasing.
Amongst all that as well, you’ll see BG exercising its judgment in whether or not we push us hard on some projects. I won’t mention the projects, but you know that we have taken judgments on a number of projects which we decided to push back in the program, and there is a good sensible decisions for good commercial and value reasons. So we push back them, some projects fall away, other new ones come in. So you are looking at here a long term sort of growth range that we’re aiming to deliver. It’s a guide for you. About the composition within that range is going to change. And as we move forward, we hope to provide a much greater level of confidence.
So, of course, the numbers that you see in this range have changed, not only as the level that we can achieve from discoveries increased by 200,000 barrels a day. If you look at the profile between now and 2020, it’s a lot fuller than it was one or – two or even one years a year-ago, has a lot more production under that curve than there was even one or two years ago. I hope that gets to the heart of your question. I mean, if we – as I mentioned in my remarks, if we delivered the top of that range, we would have grown 11% – E&P production at 11% compound for 24 years. That would be quite an achievement. That’s what we’re aiming to do.
And Brazil – sorry. FPSO size – look, FPSO size, I think you have two things you need to think about here. Firstly, the numbers, like a 100,000 and a 150,000 are barrels. Yes, there is a quite a bit of gas going through there as well. So when I talk about 2.3 million boe per day, you have to make allowances for the gas that’s going through as well. So that’s sort of grossed up in there. I will leave you to guess at how to scale the capital efficiency between a 120,000 unit and a 150,000 unit.
More importantly, I think is what we’ll be doing to debottleneck these units, because it isn’t a stretch at all of the imagination. In fact, it is the norm facilities can have 10% or even 20% additional capacity through debottlenecking process where you’ve got really high productive capacity from the wells which we do have. So that really is probably a bigger factor to put – to carry around in your mind about much they’re going to get out of these facilities. I’m sure that there are lots of models that you can drawn to have a crack at the CapEx profile between a 120,000 and a 150,000 unit.
And, please, over back here, thank you.
Paul Spedding – HSBC
Paul Spedding from HSBC. You painted a picture of Europe that’s reasonably or appears reasonably balanced. We are still getting quite a lot of the purchases of gas within Europe appearing to believe there is a glut. And as a result, it seems to me that quite a lot of the infrastructure that you will need to deliver that gas both in terms of LNG receiving terminals and pipelines seems to be sort of held up. I just wonder if you feel there is a probability or chance that Europe could actually turn into a tighter market than even your scenario shows and whether you feel that some of the EU purchases of gas are taking a bit too much of a risk with our security.
That sounds like you it's something from the Guardian. The Guardian is not here. I think that’s a reason – an interesting and reasonable observation. I mean, I think what surprised me was the recovery of gas supplied from Russia into Europe. I mean the speed with which we went from 2008 down the hill and then straight back up the hill again, it was remarkable. And after all hysteria of the pricing and the volume and what volumes have backed off in Russia and Norway estimate, I mean it’s pretty well come back to 2008 levels. And that – it is such a circumstances where you wouldn’t perhaps have expected it, so I wholeheartedly agree. I think it’s much likely to be more tight than less tight.
And, I think I agree as well, and that’s the reason why we believe that you’ll see much closer adherence to oil equivalents in pricing in Europe, because you will need that to justify the very large capital flows for investment, absolutely. Theepan at the front here, and then we’re coming over to the back to – who is that? Is that Mr. Lucas?
Theepan Jothilingam – Morgan Stanley
Hi, it’s Theepan Jothilingam, Morgan Stanley. Three questions, actually. Firstly, just a quick question on your assumptions the underlying decline rate in what was your pace or what you now shows other?
Secondly, I was just wanting to get a little bit more color, if you could flush out how you think the economics on train three in Australia would pan out?
And then, thirdly – I think you’ve given some very impressive production targets that have accelerated, I guess, one of the questions I get is more on cash flow. And over the last few years, we have seen CapEx, capital investment increase for the Group. I was wondering how you saw that going forward? And then, sort of, when exactly you saw an inflection point in terms of free cash flow rather than CapEx going into the business?
Ashley will take the cash flow. Train three economics, I mean, clearly with – as I said in my remarks, very little capital investment required in the midstream to underpin a third train. So all of the common facilities at Curtis Island, the pipeline infrastructure, I mean these are already being designed for three trains and require very little incremental CapEx to upgrade them to handle. Three, of course, you need the LNG train itself. I mean, my guess is that, unit development CapEx for this could be 40% lower than the first two trains.
We’ll be very economic indeed, irrespective of whether one – sources at 100% from equity gas or whether there is a mix of some third-party gas. I mentioned again in my remarks that we’re looking at both things and either way. And this train three looks hugely economic. Ashley, you want to take the cash flow question.
Yes. And, obviously, one of the consequences of being successful in growing your resource base is that, you have to grow your investment alongside that. And, consequently, we have seen investment rising in recent years. When you look at the major areas of investment, Australia, Brazil, US, to a lesser extent the UK, the striking thing about those first three is the rate at which production builds up and you then have to factor in the LNG earnings and cash flow in some of those projects.
So I really go back to the comment I made earlier, which is you have two things going on at the same time, capital going in and then the number of major projects coming on stream in quick succession with very steep ramp-up profiles. So we do expect that operating cash flow will grow very strongly. Usually caveat about prices, but nevertheless, you can see production ramping up very quickly.
Your question about the peak, obviously we’ve got now three years of intensive investment. And through that three-year period, these projects will come on sequentially. And, once you get beyond that, as I said earlier, I think the sheer weight of the cash flow from these projects will give us some questions I think about how to utilize the cash.
Decline rates is a little bit of a – sorry, have you finished Ashley?
I beg your pardon – is a little bit of a complex equation, of course, because it’s not one field, because it’s sort of declining, it’s a mixture of fields which are quite old, mature like Armada, for example, in the North Sea, mixed with other fields where there is ongoing development like for example, in the West Delta deep fields where we’ve got ongoing phases will have at least nine or 10 phases of development there, and we’re at phase seven. So it’s a little bit difficult.
But if you just have a look at the chart here and you take the combination of all of those things together, I mean 2010, those fields produced say, for argument sake, you can pick it off of here 600,000 barrels and that was reduced by less than half over 10-year period. So 50% – I’d say 50% decline over 10-year period, that’s a compound annual average decline rate of what, 3% or 4%.
So actually, in from that perspective, it’s – as we’ve always said, quite a low decline rate from the existing assets. It doesn’t mean to say you get that for free. It’s quite a lot of CapEx that goes in to maintaining that that plateau. But I’ll leave you to pick the numbers off. I’m afraid there is no simple answer to that question, given the combination of many fields rolled into those other assets.
Now, we’re going over to the back.
Jon Rigby – UBS
Yes, it’s Jon Rigby from UBS. I have two gas questions, and because it’s Ashley’s last show, I felt duty bound to ask a financial one as well. So on the gas ones, firstly on the US, I mean I look in the screen, you were looking at four, you’re talking to three for economic breakeven, but you’re using reference price of seven, I just wondered whether how I square that circle, and maybe if you can give some insight into what you think actually prices might go.
The second is, I think Martin will be well aware of this, as counting terminals is probably not a great guide for inferring demand. I mean, the US, you’d have gone in and complete your own direction if you had done that. So is China looking at terminal is the right thing to do? And, in indeed, could China go the same direction as the US? Have you got any comments on its internal capacity to generate shale gas and tight gas?
And then, on the financial one, actually is the highlight of my question is, you referenced tax rights for this year or 2011, has the mix effects change in the portfolio, how do you see the tax rate changing over maybe the next five years, if possible?
Let me take the tax question first. Commonly, we don’t – as you know, John, go out more than 12 months on tax rate. There are many moving parts in the tax calculation. I think that, as we go further out, we will see a change in mix more production out of Australia, more LNG profits, and of course, more profits out of Brazil. That will all have an effect. But it just won’t be sensible for me to try and predict precisely where tax rates will go beyond 2011, I’m going to say that for Fabio, when he takes –
Okay, I’ll take the first two. First of all, reference price; our reference price is $5.50 not $7. That’s in the appendix on page 81. And actually $5.50 is not that north of where we could imagine in the long run price of gas to be in the US. I mean, $5 you wouldn’t be far wrong, is going to have excursions north of that, and indeed excursions south.
But just for curiosity, if nothing else, I mean on the really cold snap last week when it was 12 below F in Texas last week, we were pulling a 106 bcf a day in the US. So there is a strong later demand out there and that demand is constantly being reinforced by state policy as opposed to federal policy. And I think a big drive towards the transportation sector, which I believe is going to start working as people look at efficiency as one of the long-term solutions in the United States.
If I can just add.
It’s very important to distinguish or draw a distinction between the reference prices that we use for ease of aggregation in our financial projections and the prices that we use for economic screening and breakeven, so they’re completely different. And the $5.50 simply for ease of aggregation if you changed it by $0.50 or $1 wouldn’t have a dramatic effect on most of what we talked about today.
Yes, indeed. I mean we’re talking about economic breakeven at $3.20 that’s essentially what’s driving the core area economics at the moment in Haynesville, and we believe we can manage to achieve the same in what will become a core areas in the Marcellus.
A couple of more points on the US then. Just as we look at, we’re the bottom end, the bottom quartile, the best quartile of the cost curve. That is not going to supply the entire United States. The cost curve does rise sharply, although there is a – there is some flat spot in it. And we’ve got to remember, the decline is quite significant. And as Frank showed on his slide, with increasing proportion of unconventional within the US gas mix, that number is just going up all the time. So 25%, 30% year-on-year decline rates is a big pull on new production.
In China, I thought some – I don’t believe they will be stranded terminals, because I think as I tried to say in my remarks, it doesn’t take very much change in China to make a very, very big impact. I mean, the 1% case I gave you, we don’t need for China less than 5% gas penetration, which against India is half, and against most developed economies is almost nothing.
So I think our assumptions have been quite conservative and you can really flex at them very quickly. We are seeing very aggressive buying patterns from the Chinese, as I hope those, curves showed you. We’ve got to almost the 2020, 2010 expectation in a halfway before we got to it. So it’s – my sense is that those terminals have been built for a reason, and we’re going to see them buying LNG on a long-term basis – on an oil index basis.
Lucas Herrmann – Deutsche
Frank, thanks very much. So it’s Lucas Herrmann with Deutsche. Three quick ones. The first for you Martin. Elba, I mean you’re still taking 2 million tons a year, and to what extent are you able to change configuration around gas? And it feels as though you’re leaving quite a lot of value on the table, given the opportunity that might exist to sell the gas at LNG and other markets.
And then, Frank, I just wondered if you could comment, any liquids or condensate associated with Tanzania that you’d care to comment on. And, finally, just if you could – it was just a question of definition on one of your slides, you talked about 2P or you talked about Brazilian oil pricing off Brent, I got the impression you meant the equivalent to Brent, and then a $4 transport charge.
Lucas Herrmann – Deutsche
Just an explanation as to, I think the assumptions and 8% discount or so. But –
So I mean it costs you $4 to access oil prices Brent. Yes, that’s essentially what we’re saying, $4. Liquids condensate; too soon to share everything with you on what’s happening in Tanzania. What I would say to you is, there are a wide variety of concepts that we need to explore there, okay? So this is just the beginning in relatively straightforward setting, beginning to do these tests and having encouraging results, lot of world to go. So this is not going to be something that’s we understand the whole story. Next year, this can be some years of work, I think.
Yes. I mean, Elba, I had made three points, I think. First of all, by 2015, Elba will be about 10% on a contracted basis. I mean that’s the fact. The second point is that we do, of course, at all times try and debottleneck the domestic supplies into Georgia, Northern Florida, to tell out some of that LNG, and quite often we’re very successful in doing that. But the third point I’d make is if you’d ask me November, where you can get the highest price for LNG anywhere in the world, it would have been in Georgia, which was paying $18 per million Btu. So it isn’t all bad. And does regionally dislocated markets in the United States provide exceptional value at a times of big weather excursion. So it’s not always as bleak as it looks.
Yes, in the middle here, please. This gentleman has been very patient.
Oswald Clint – Sanford Bernstein
Hi. Oswald Clint, Sanford Bernstein. Yes, just a question on the US again, please. In terms of your unconventional assets, a lot of capital going over to the oil shale plays at the moment there, I assume that’s not something you’re interested in, and does that mean you really have a materiality level in unconventional assets in the US at this point in time?
Secondly, looking – I’m just curious about the Panama Canal opening up in 2014 to LNG tankers. Is it that something you’re looking at? Is there anything opportunity there to start shifting volumes around?
And then, thirdly, just on the 75% of LNG volumes linked to oil by 2015, can you say if there is a proportion of that linked under S-curve type formulas or how particularly caps with the oil price? Thanks.
I’m afraid, the last one we won’t answer, because of the commerciality. The first two oil shale we’re not playing in that space at the moment. In respect to materiality, we’re in a learning process right now. Very pleased with the progress we’ve made. 60% uplift in resources since we entered the Haynesville, just starting our appraisal work in Marcellus.
I think the name of the game right now is to understand what we’ve got to optimize the portfolio, so you may well see things going out and things coming in. And, because the name of the game, as I mentioned in my remarks earlier is to earn the best quality rocks and have the lowest cost structure, without this, you will not have a sustainable strategy. This is very important that where we have areas that are not the best, that we wrote – and it isn’t the case in any area that everything is going to be high quality, so we rotate out of the portfolio sound properties and we rotate into the portfolio of better properties.
And then, of course, there are the opportunities to aggregate just opposed properties, where there are independent owners of small blocks of acreage that can’t develop the infrastructure needed to evacuate that, to export those volumes, and there are opportunities rather for doing deals are for requiring acreage. So that’s really the name of the game.
We’re not doing all the shale at the moment. We’re trying to optimize what we’ve got. And the materiality, we’ve got to a level which is sufficient to sustain a material business, and I’m not making any further judgment at this stage. We’ll see what the quality is of everything, we’ve got to see how it evolves, and we’ll do this sort of optimization the portfolio. But we’re not – we’re not doing, we’re not contemplating any major acquisitions, for example, present we don’t need to do that. We’ve got to, as you’ve seen quite a program in front of us, as it stands.
Panama; I mean, clearly – I mean to Fred’s point earlier on about exports of LNG from the US, if you contemplating exports in from the Gulf, then the twin track of the Panama Canal by 2014 or 2015 is going to be a significant transportation advantage. I think what we have yet to understand about that, clearly it’s been sized such that, it will take certainly Atlantic max sized ships which would put into the, sort of 175 category, maybe larger. I don’t know whether it will take a key flex or not. But, anyway, what has not been worked out is the pricing formally for the Canal, so that remains to be seen, and clearly that will make a difference one way or another on the export economics. But it clearly, it does open up different patterns, yes.
Okay. With that – we’ve got one more question here. So one more question, and then, I think we’re going to call it a day. Everyone seems to be replete.
Rahim Karim – Barclays Capital
Thanks. It's Rahim Karim from Barclays Capital. Frank, I just want to ask you a question around Brazil. Obviously, projections that you have given around the 550,000 barrels a day of production by 2020 are based on your own assessments. Petrobras hasn't come out and necessarily given out the same levels for that period of time. How do you see your negotiations with your partners going through, what risks do you see, and how do you see that progressing over the next two or three years?
I mean, we base this on our own assessment of what we believe will be economically rational. Once you put in place the large building blocks of infrastructure, then, of course, it becomes economically rational to do infill drilling, to do debottlenecking, do install incremental FPSOs in the flanks of the field. For example, make use of the existing gas evacuation infrastructure and oil evacuation infrastructure, possibly other things like floating LNG infrastructure. These sort of things will become economically rational to do.
And, is therefore, BG’s field development modeling which is based absolutely on the current understanding of the reserves level that we have, the reserves and resources that we have in these field, which delivers what we believe is an economically rational production profile. I mean at the moment, there is a single phase of development, and that is insufficient to optimize economically the recovery of resources from this field.
So do I think it’s just going to stop and leave perhaps some of the most value barrels around in the ground? I don’t think so. So this is a little ahead of consortium agreements, but it will be economically rational. I would say that it is very clear that both Petrobras is the operator and other consortium members in the two consortia, very, very committed to doing what we’re doing. I mean, Petrobras is doing a remarkable job.
If you think we’ve come only just a little more than four years from the first discovery well, to having progressing 11 FPSOs and tendering another two, 13 FPSOs with all of this production capacity in a little more than four years, that is remarkable progress, and is a testament to their performance and the quality of the relationships in the consortium. So I feel pretty confident. People have worried a lot about this, will they go and do Franco first and leave you stranded? It doesn't look like it actually, given the progress we’re making. I think that that’s a concern we can set aside.
I mean the acid test here, of course, is that the consortium has jointly committed to these FPSOs and the drilling expenditure there. That tells you, I think, gives you answer.
Rahim Karim – Barclays Capital
Rahim Karim – Barclays Capital
Right. Well, let me say, thank you very much for the full attendance this afternoon, and for very interesting question-and-answer session. We look forward to hearing more from you and to speaking with you again with our first quarter results, which are around – in the early part of May. Thank you very much indeed.
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