Centrica plc (LON:CNA)

Earnings Call: H2 2012

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Feb 27, 2013

Well, good morning, everybody. It's great to see so many people here. We've got a fuller morning than normal this morning, as you know, covering both results and then the strategic evolution of the business. The second part starts at 11:00, and it is webcast, so we're going to be pretty time-disciplined this morning so that we will restart at 11:00 following a bit of a break after the results. It's three years since we defined the strategic objectives to build a more sustainable, vertically integrated, cost-effective, and customer-focused business with meaningful geographic diversity. We were clear that to achieve this objective, we would need to grow British Gas, acquire upstream assets on value-creative terms, and expand the scale of our North American operation. I'm pleased to confirm that in 2012, I am sure we demonstrated, through strong operational performance and acquisitions, our considerable progress in achieving these strategic goals. Delivering profits, as you've seen, of some GBP 1.4 billion, earnings per share of GBP 0.271, and a 6% increase in dividend to GBP 0.164 per share. In the U.K., the year brought many challenges, with periods of colder weather compared to very mild conditions of 2011, contributing to higher energy bills and with material changes in the regulatory environment. The management team dealt with all of the turbulence with great professionalism and commitment. British Gas took the lead in simplifying tariffs and implementing changes consistent with Ofgem's proposals for retail market reform. In parallel, we continued to innovate with smart metering to help consumers manage their energy usage and to support customers with free insulation to reduce their consumption. A relentless focus on cost management helped British Gas implement the lowest tariff increase of all the major energy suppliers, necessitated by higher wholesale energy costs, government-driven green energy costs, and the imposition of additional infrastructure charges. Nevertheless, the very real concerns of hard-pressed consumers, fueled by external commentary, has impacted public trust in the industry and in British Gas as the nation's largest energy supplier, in particular. It is important that all stakeholders understand the importance of our contribution to the U.K. economy through the service we provide to customers, the investment we make, the security of supply we deliver for the nation, the tax we pay to the government, the employment opportunities we offer, and the rewards we deliver to our shareholders. This will remain a key agenda item for the company in the months to come. Upstream, we invested GBP 2 billion in gas and oil assets. In parallel, we achieved first power from our Lincs offshore wind farm and worked with our partners in extending the life of the existing nuclear fleet. After long and careful consideration, we took the decision not to participate in new nuclear construction with EDF due to higher anticipated costs and a lengthened construction phase. Our commitment to balance sheet discipline is reflected in our decision to return some of the capital we had raised for the purpose through a GBP 500 million share repurchase program, which will commence forthwith. In North America, a carefully executed strategy of operational efficiencies, organic growth, and customer acquisition helped us to further expand our business, putting us on track to double its profitability. With a change in the center of gravity of our North American activities, we moved the corporate headquarters from Toronto to Houston, and our ambition to further extend our role in this market remains a strategic priority. Our overall vision to be the leading integrated energy company with customers at our core remains true. The way in which we achieve this, however, must reflect the changes in markets and sources of supply, together with a constant assessment of costs and return for our shareholders. In the session later this morning, Sam will review in some detail our new strategic priorities and the shape of the business that will evolve. The year ahead is going to bring new challenges, which will demand even greater efforts from the team. In order to ensure that the organization of our management team is appropriate for the task ahead, with effect from the 1st of July, the group will migrate from a regional structure to an international functional structure. Chris Weston will assume responsibility for our downstream operations, and Mark Hanafin will assume responsibility for our upstream operations across the group. Just a word on Phil Bentley. After a successful career spanning 12 years with Centrica, Phil's going to be stepping down from his role as Managing Director of British Gas and a board member of Centrica on the 30th of June, and he will leave the company by the end of this year. Phil has made a substantial contribution to the development of this business, initially as Finance Director, and for the last six years as Managing Director of British Gas. As Chairman, and on behalf of the board, I just want to publicly thank Phil for all that he's achieved, and indeed will achieve in the closing months of his tenure. Finally, I'm confident that the bench strength we enjoy, the mindset that we have, the new management structure, and business model we have created will ensure we continue to deliver both sound performance and strong cash flows. This will enable us to invest in customer service, supply security, and shareholder reward in the year ahead. With that, I will now hand over to Nick. Thank you, Roger. Good morning, everybody. As usual, let me start with the commodity price backdrop to these results. Average upstream gas and oil prices in 2012 were actually very similar to those in 2011. However, they have been at these higher levels for longer, so the effect was felt more, both upstream and downstream, without the delay from hedging seen the year before. Spot spreads, as you know, were very much lower, much lower than 2011, impacting the running pattern of our CCGTs and feeding through into outright power prices. In contrast, our competitors in the last year before the end of free carbon did benefit from much higher dark spreads for their coal stations. Commodity prices were not, however, the most significant external factor in the year-over-year performance. That, as you can see, was the weather. You'll remember that 2011 was unusually warm. In 2012, despite a warm Q1, overall, the average temperature in the U.K. was slightly colder than norm. Gas consumption for customer for British Gas Residential increased by 12% as a result. With that background, the group performed well in 2012, delivering improved operating results in every business unit. For the group as a whole, revenue was up 5%, reflecting the higher gas consumption in the U.K. and high average retail prices here. Operating profit, as you can see, increased 14% with Centrica Energy being helped by acquisitions, was the biggest contributor to that increase. The tax rate rose to 44% as a result of the larger contribution from the more highly taxed upstream, leaving earnings up just over 5% at GBP 1.4 billion. That translates to 27.1 pence per share. The dividend for the full year will be 16.4 pence per share, an increase of 6%, 3% more than inflation. With the dividend paid entirely in cash, that's a return to shareholders of over GBP 850 million, adding to the GBP 500 million of cash being returned through the share buyback we announced earlier this month. Here's the divisional breakdown of the results, and you can see how each of the four business units have generated additional profit. Starting with British Gas, here profits increased by 9% to just under GBP 1.1 billion. Within that, Residential Energy came in at just over GBP 600 million, in line with our target. The colder weather resulted in higher volumes, and higher average retail prices covered higher external costs, both commodity and non-commodity, leaving margins only slightly down at 6.6%. Residential Services continues to perform well despite, giving us. We were not able to mitigate fully the impact of Power contributed to the increase. Gas production volumes were up by 13%, driven by the assets acquired from Statoil and our increased interest in Statfjord, both of which were owned for eight months of the year. Those additional volumes offset lower production from Morecambe, where we did have some gas blending challenges in the first half, you'll remember, as well as seeing the continued natural decline of the field. Liquids production was up 30%, with the increase all coming in the second half, driven by the acquisition of assets from Total, all of which are oil producing. Hedging had held back realized prices upstream in 2011, so we did see higher realized prices in 2012, despite, as I said earlier, average month-ahead prices being largely unchanged. With less drilling success, we did take a higher exploration write-offs in 2012 and a write-down in Sine following poor flow results from one of the wells that we drilled there. That did mean that the operating profit for the upstream business came in below expectations that we had. However, the high tax rate meant that the effect on earnings wasn't that significant. The power result was perhaps surprisingly strong, in part reflecting the profit we recorded when we sold down 50% of our interest in the Round Three offshore wind Irish Sea zone, bringing in DONG as a partner. However, the underlying trading result from the CCGTs was still poor with the fleet breaking even. Although our realized spark spread increased, as you can see, that was due to peak running and hedging, and low market spark spreads meant that we ran the stations much less. In contrast, nuclear output remained high with slightly higher realized prices also helping the nuclear result. Storage benefited in the second half from the higher SBU prices for the 2012/13 storage year, driven by higher seasonal spreads at the end of 2011 and early in 2012, which also enabled better optimization performance. As a result, profit increased by over 15% to GBP 89 million. However, summer/winter spreads have narrowed more recently, and the outlook for the coming 2013/14 storage year is less positive. In North America, Direct Energy performed well, particularly in the second half. For the full-year profit increased by 6% to $331 million. Despite the expected decline in Ontario and unfavorable weather, residential energy was only slightly down, benefiting from the three acquisitions made in 2011. The 2012 acquisition of Energetix and NYSEG has yet to contribute significantly because of integration costs. Business Energy Supply continued to grow strongly with volumes up 11%, driving a 17% increase in profit. In a tough environment, services performed well, increasing profits by close to 20%, driven by higher revenue and higher margins. With North American gas prices reaching new lows in the first half, conditions were challenging for our upstream business, of course. Gas production fell as we switched development activity to liquid-rich opportunities. But with hedges rolling off, the switch to liquids was not enough to prevent average realized prices dropping. That did leave returns well below our cost of capital, with capital including assets acquired some years ago in a much higher price environment. Turning to cash flow, you can see that cash generation remains strong with EBITDA of over $3.6 billion in 2012 and close to $4 billion with the acquisitions pro forma-ed in for a full year. CapEx was also higher, of course, with the acquisitions costing $1.2 billion, pushing net debt up to just over $4 billion. That was lower than expectations due to tight control of working capital and the phasing of tax payments. Looking at the CapEx, organic CapEx was $1.5 billion. The majority of that went into the upstream business. York was the largest single project, but there was also significant spend at Rhyl, Statfjord, and Ensign, plus the initial spend on the Cygnus project. In power, the major part of the spend was on the Lincs wind farm. Looking down the bottom, 2012 acquisitions include the three major Norwegian and U.K. upstream deals, plus the bolt-ons in North America. Looking forward to 2013, upstream CapEx, and this excludes North American upstream, is expected to be around GBP 1 billion, with the completion of York, high spend on Cygnus, and continued development of Statfjord and Valemon. In power, we expect to complete the Lincs wind farm with the required spend there potentially offset by the sale of the transmission assets out of the Lincs joint venture. We may also commit up to GBP 200 million of Race Bank, but that does depend on FID being taken, which in turn depends on the economics of the project being attractive. So at this stage, we are only including the pre-FID spend in the guidance figures you see there. In summary then, we were able to deliver earnings growth through higher profits across the group, benefiting from normal weather in the U.K. and from acquisitions upstream. The big change in 2013, of course, is the loss of free carbon for the CCGTs, which with low spark spreads and hedges rolling off as well, will push the fleet into significant losses. In addition, the amendment to IAS 19 will increase pension charges in the accounts, albeit with no cash impact. We are looking for growth elsewhere in the group to more than offset these negatives with a full year of the upstream acquisitions and continued growth expected from BGS and in North America. With that, I will hand you over to Sam. Thank you very much, Nick. Good morning, everyone. As you've heard, the business performed well in 2012 in a challenging environment, delivering year-on-year earnings growth and a further increase in the dividend, in addition to launching a GBP 500 million share repurchase program. We invested GBP 2.7 billion in total across the group, both organically and through acquisition, mainly to help energy security and secure supplies for our U.K. customers. Downstream, British Gas had a strong year despite facing increased cost in the supply of energy and the continued depressed economic climate. Upstream, we saw the impact of recent acquisitions flowing through to the bottom line, especially from our new Norwegian assets. In North America, we achieved continued growth in profits, adding more customers in the U.S. organically and also through bolt-on acquisitions. We are now on track to deliver our group-wide GBP 500 million cost reduction program with a clear objective of sharpening the business and maintaining our competitive edge for the benefit of customers and shareholders alike. With household budgets continuing to feel the squeeze, we are committed to doing everything we can to help our customers. We've made sure that the energy choices they have are simple and transparent by making our bills easier to understand and reducing the number of tariffs that we offer. This month, we've launched our personalized tariff checker, letting customers know if they are on the best value tariff for them. We've also further improved our high levels of customer service. Our net promoter score increased once again, and we were awarded the top five-star rating from Consumer Focus. In services, we improved our retention rates across the product range. We also spend more than any other energy supplier on those who are most in need of support. This winter, over 400,000 of our most vulnerable customers will again receive the Warm Home Discount, worth GBP 130 off their bill. We've continued to drive our cost down across the group, but particularly at British Gas, with the clear objective of reducing costs without impacting customer service. At British Gas, we are at the forefront of innovations which will transform the energy supply industry and improve the energy efficiency of the home. Our improved online platform handled 13% more transactions than in 2011, achieving a better customer experience at lower cost. We now have over 3 million online customers in the U.K., with a third of all energy bills now sent electronically. Our new remote heating control product is proving to be very popular, this allows customers to monitor and control their energy use when they are away from the home. Already, 15,000 customers have taken this product in the first few months since launch. In terms of energy efficiency, we have completed over 1.7 million insulation jobs under the CERT and CES programs. The measures we have undertaken over the past three years alone are delivering savings of around 2.5 million tons of CO2 each year, equivalent to adding 1.8 gigawatts of offshore wind capacity at, of course, significantly lower cost. We have now installed over 800,000 smart meters for homes and businesses, substantially more than any other U.K. energy supplier, to help customers manage their bills. Already, we have seen a 20% reduction in call volumes and a halving of complaints from customers with a smart meter. Upstream in Centrica Energy, we continue to spend capital to secure energy supplies for the U.K., investing GBP 2 billion in the North Sea oil and gas assets last year. Production of gas and liquids was up 18% year-on-year, benefiting from those recent acquisitions. Even after taking into account of production for the year, our U.K. proven and probable reserves increased by more than a quarter, a step change in the scale of our portfolio. We passed a number of key milestones, achieving first gas from three new developments, Ensign, Seven Seas, and Atla, with first gas from York imminent and Rhyl also expected to produce in the next few weeks. We gave the go-ahead for the Cygnus development, the biggest gas discovery in the southern North Sea for 25 years. In power generation, we achieved good operational performance across our fleet, despite the continuing challenging environment for gas-fired plant. The nuclear fleet performed particularly well, achieving 60 terawatt-hours of output, the highest level for seven years. Securing life extensions at Hinkley Point B and Hunterston B was another key milestone. In offshore wind, we achieved first power from our Lincs offshore wind farm and expect it to be fully commissioned later this year. We are also investing for value at South Humber, reblading the turbines to improve the station's efficiency. Our investments in 2012 have materially increased the scale and geographic diversity of our upstream business. We are less reliant on Morecambe, which represents a smaller proportion of our total production. Norway is now a core part of our portfolio, reflecting the acquisitions we have made and our success with the drill bit, with a balanced portfolio of producing, development, and exploration assets. In power generation, we retain options to invest in CCGTs and offshore wind. We now have planning consent for Race Bank, our next offshore wind project. However, the regulatory environment is in transition, and we are currently in discussions with a financial partner and the government regarding the necessary economic framework to take FID. We have also established a joint venture with DONG Energy to co-develop the Round Three Irish Sea wind farm zone, the Celtic Array. As always, we will only invest in these projects where we see value assigned to our core competencies. In this context, earlier this month, we announced that we would not participate in new nuclear build in the U.K. Whilst we believe that nuclear power has an important role to play in the U.K.'s energy mix, the likely cost, and particularly the timescale of this project, led us to conclude that it was not in the best interest of Centrica shareholders for us to participate. Our North American business once again delivered good profit growth despite very low natural gas prices. We're benefiting from enhanced scale and synergies downstream with the completion of the Energetix and NYSEG Solutions acquisitions in 2012. Restrictive competition regulations, however, remain in place in Ontario. This business, however, is no longer material, and we expect it to make up only 5% of DE's residential energy profit in 2013. We're actively managing the cost base of the business to continue serving our customers as efficiently as possible. In DE Business, we're delivering strong organic growth, with electricity volumes up 11% last year. Direct Energy Services is also performing well, gaining market share. Services contracts were up 5%, despite a challenging market environment for the services industry. Direct Energy Upstream continues to face a low wholesale price environment, but liquids production doubled, and effective optimization in both gas and power enabled profits to be maintained. We've developed a successful downstream acquisition and integration capability in North America, which is delivering both growth and efficiencies. We now have 3.5 million residential energy customers, with 1.4 million of these in the U.S. Northeast. Customer satisfaction levels have increased, and our innovation products, such as our prepaid Power2Go product and Free Power Saturdays, continue to attract customers. In services, the acquisitions of Clockwork and Home Warranty of America have created the platform for us to cross-sell services to our energy customer base. Over time to also introduce service protection plans, building on our experience from the U.K. services market. Upstream, although natural gas prices remain low, we now have an expanded presence, having increased reserves by around 60% in the last three years with more material liquids presence. The health and safety of our staff and customers remains a core priority to protect our employees, contractors, customers, and the wider public. Upstream, we put particular emphasis on process safety, while downstream we focus on the safety of the public and our engineers through training, rigorous monitoring, and assurance. Initiatives across the group include reinforcing a positive and proactive safety culture across all our businesses, and they led to further improvements last year. Our lost time injury rate fell by 20%, and we've made encouraging improvements in road safety and recorded no significant process safety events in 2012. We'll continue to target further improvements in the year ahead. In summary, much has been achieved across the group, both in the last year and since we set out the strategic priorities three years ago. We have delivered against each one. First, to grow British Gas. In BGR, we're delivering stable profits through the cycle. We've taken a lead in ensuring that our tariffs and bills are simple and clear, and our customer retention is strong, increasing over the last three years to 91%, reflecting the services and competitive pricing, all underpinned by a constant focus on efficiency and cost. In BGS, we've increased profitability by more than a third despite the weak economy, and here too, retention remains strong, demonstrating the value that customers place on our products and the high levels of service that our engineers deliver. In BGB, we have signed our first multi-year energy performance contracts with a strong pipeline of growth for the year ahead. We are investing in our back-office systems to improve service at reduced cost. We have a new management team in place to drive the business forward. Across British Gas, we are on track to deliver our cost savings targets, taking out GBP 300 million of costs through a relentless focus on service and efficiency. We have established clear leadership in systems, online, and smart, providing us with the platform for growth through technology and innovation. Our second priority, to deliver value from our growing upstream business. Here we have built a significantly larger, more geographically diverse business. Our record of growth in Norway is particularly a strong example. In gas and oil, over the three years, we have increased reserves in production by 50% and doubled our cash generation, reflecting acquisitions and also our success in bringing new projects on stream. We have achieved first gas from nine projects and recorded above average exploration success with eight discoveries out of 15 wells drilled in the North Sea and Irish Sea since the start of 2010. In power, we are established as a leader in offshore wind, working with key partners and enhancing our returns through efficient financing structures. In gas-fired generation, we have taken prompt action to optimize the performance of our CCGT fleet, closing loss-making stations where required, and investing to optimize the remaining assets where appropriate. In nuclear, the strong performance of the existing fleet underlines the quality of our original investment in British Energy, with the life extensions adding additional value, as well as helping to maintain energy supplies for the U.K. Our decision not to proceed with new nuclear underlines our commitment to strong capital discipline. Turning to the third priority, to build an integrated North American business. Here we have increased our scale both upstream and downstream, where we see attractive value and a good fit with our core capabilities. Operating profit is up 55% with U.S. profits up 72%, putting us well on the way to our target of doubling the profitability of the business. Customer numbers in our core U.S. markets are up 75%, more than offsetting the impact of the regulatory environment in Ontario. Profits in DE business have more than trebled, with volumes up over 50%. In services, we now have a true multi-state capability with a platform for growth through cross-sell opportunities and protection plan offerings. Our downstream business is delivering a much-improved return on capital, up from 9% to 13%. We have taken advantage of the low gas price environment to treble our upstream resource base and increase production by 50% in North America. Our fourth priority, to drive superior financial returns. Our EBITDA is now approaching GBP 4 billion, up from GBP 2.6 billion just three years ago. EPS is up by a quarter. Dividends per share are up by 28%, well ahead of the FTSE 100 index, and contributing to a total shareholder return of 36% over the period. We have been successful, but the energy landscape has changed significantly in the last three years, and we cannot stand still. We have to evolve to meet the challenges of this new world, and that is why we are now setting out new strategic priorities. First, to innovate, to drive growth and service excellence. Second, to integrate our natural gas business linked to our core markets. Third, to increase our returns through efficiency and continued capital discipline. To deliver these new strategic priorities, we are changing our management to a global functional organization under Chris Weston, responsible for international downstream, and Mark Hanafin, responsible for international upstream. I would like to take this opportunity of endorsing the Chairman's remarks about the very significant contribution that Phil Bentley has made to the transformation of British Gas. He has been instrumental in restructuring, reinvigorating, and materially improving the performance of the business by raising customer service, lowering costs, and increased productivity. We will be expanding on these new priorities and explaining what they mean for the business in the second session later this morning. For now, in conclusion, we have delivered a strong performance in 2012, with continued earnings growth. We have enhanced the scale of our business upstream with increasing geographic diversity and the capabilities to achieve future growth. We have a robust balance sheet and generate strong cash flows, retaining a number of attractive investment opportunities for the group. We are now setting out refreshed strategic priorities to adapt to a new energy landscape, reshaping our management team to build upon our core competencies to ensure our future success. With that, I think I would now like to open it up to questions. I would suggest that as we have a separate session later on strategy, we mainly focus in the Q&A session on 2012 and current business conditions. Although, of course, we are happy to take questions on strategy as well, but the more of those, I think we leave until after you have heard the strategy presentation, probably the better. With that, I think we can go to our questions. Thank you, Sam. We have got about 35 minutes, which will give us about a 10-15 minute break before the next session for questions and focus on the current and past, as Sam suggested. We will start in the middle, and then we will work around. Please could you say who you are and where you are from. Hi. Yeah. Hello. Jonathan Constable from Nomura. First question, just on the financial position, really. I'll put the argument this is about where we are now rather than the strategy, but you might be able to push back. Accounting for the expected effects of the share buyback, how much financial headroom do you think that you have for acquisitions over the next 12 months? So an update on the financial position. Secondly, just on the storage spreads. If we look at what you've achieved in 2012 and where you're seeing the seasonal spreads in the forward markets, how should we think about the profitability of this business developing from 2014 onwards? We will be talking in more detail, John, about the headroom and the opportunities that the balance sheet presents, in addition to obviously, of course, to the organic opportunities that we see in the strategy session. I'll, recognizing that it is a critical question, let Nick speak to that, and then I'll come back and talk about storage spreads. John, the key RCF to debt metric actually will improve in 2013 because we will have a full year of the acquisitions in, of course. If you do just some simple maths against a mid-20s ratio, you would come up with a figure around GBP 2 billion, even after the share buyback. Clearly, what you do with that headroom, the characteristics, the capital characteristics, the risk profile of whatever you spend it on would be critical in thinking about what you would spend. Indeed, how you financed any M&A partnering, et cetera, would also be critical. But if that gives you a feel for the scale of it. Thank you. I think in terms of storage spreads, we did well in 2012, really picking the top of the market for a lot of the SBUs that we sold. We had seen a softer recent market conditions, and I think you could expect the storage spreads to be down by about 10%. Yeah, something in the 23, 24 pence per SPU for the 2013 and 2014 storage year, which will mean lower profits overall. Okay, let's go in the middle. Please. Martin Brough from Deutsche Bank. Not to look forward at this point, but if you look backwards over the last five years from 2007 to 2012, what kind of post-tax return on capital do you feel you've got from the North American business and from the upstream business? Are you happy with that? Is that the kind of thing that you would be happy with over the next five years? The answer to that is, in a nutshell, Martin, would we be happy with it? Yes. But is it a continuously improving picture also? Yes. Both in North America, as I indicated in the downstream, we have seen our ROC go from 9% to 13%. In the upstream piece of North America, actually, the investments have been closer to the cost of capital because of the collapse in the overall NBP price as a result of shale gas. But actually, despite that, our Wildcat Hills acquisition is still making a reasonable return. We will talk more about that in the second session. If you look at our upstream investments, the big ones obviously being Venture, and if you look at British Energy, we are above the cost of capital. British Energy clearly helped by a much-improved output situation. Despite the write-off that we had to take for new build, that was more than covered by the benefits that we are seeing from life extensions on the plant that we had not previously anticipated. Venture, clearly the economics of that were very severely adversely impacted by the change in taxes that we had and the increase in supplementary corporation tax in 2010. But despite that, as a result of exploration success, we are still above the cost of capital. As we start to bring new fields from the Venture portfolio on, then actually the pre-productive capital starts to come down, and that actually will improve our ROCE as well as our IRR going up, going forward. But Nick, Yeah, I think the last point is key. Because we are making mid-teens returns on the productive capital in the upstream, despite the tax hit that Sam refers to. The challenge overall is we have got a lot of pre-productive capital at the moment because we do not have, other than Morecambe, we do not have assets we built 10 years ago. You will see that average out as we go forwards and the overall return rise as a result. Lakis. Lakis Athanasiou, independent analyst. Three questions. One factual. Can you say what your RCF to debt metric you calculate for the end of 2012 is, please? I think you gave a number for us last year. You did not give one this year. Secondly, on the new ECO coming in, can you give us a feel for where you think the spending level is going to come out? Because there seems to be a lot of controversy in the industry between what government is estimating and what some other commentators are saying. On the government estimates, your share would come out something like GBP 400 million. Others seem to be suggesting nearly double that. Also, are there going to be any accounting funders or is it just going to be a pay-as-you-go type of approach? And thirdly, you might want to leave until the strategy thing, but can you give us a bit of color on the GBP 1 billion upstream spend for gas and oil in the sense of how much in there is there for exploration and appraisal? How much is there for assumptions on development of non-2P reserves? And also if there was any deferred acquisition cost, because there is some sizable stuff coming through from this year in that GBP 1 billion number. Well, if I take the first one, the RCF to debt is in the next presentation, actually. So it was 29% in 2012. Do you want to do ECO? I think on ECO, we are anticipating. You are absolutely right, Lakis, there is a range of views here. I think the industry views all believe actually the cost of the ECO program is going to be rather more substantial than the Department of Energy and Climate Change. We are anticipating a cost in the order of GBP 600 million-GBP 650 million. But we will be accounting for this as we spend it rather than accruing for it. I think that is the methodology that has been agreed by the industry. On the upstream CapEx, within the GBP 1 billion for 2013, there is between GBP 100 million and GBP 150 million on exploration. Pretty much all of it is on 2P, just because it is in development, apart from the exploration piece, clearly. So they are already in 2P reserves. I do not think there is any deferred acquisition cost in that GBP 1 billion. Thank you. Okay. Start at the back and then work forward, please. Yeah. Please. Hi, it's Mark Freshney from Credit Suisse. Just two questions. Firstly, something you said, Nick, just to pick you up on that. You mentioned that regarding 2013, the financial outlook, you were looking for growth. Can I just be clear, do you expect earnings growth this year in 2013? My second question is, regardless of the absolute level, Ofgem have their margin guidance or margin illustrations they give. Those show retail supply margins going up. Can I just confirm whether that's something that you're seeing and how you're dealing with that? Yeah. On the earnings growth, obviously, it's very early in the year to be giving specific guidance. But consensus is showing some earnings growth to offset the negatives of CCGT, loss of free carbon, and the pensions hit. We're comfortable where the consensus is at the moment. Can I just build on that and say that I think it is very early days, but the year has got off to a good start. I think, Mark, in terms of. Remind me your second question, which Ofgem. Ofgem. Just Ofgem's Yes rolling margin guidance. I think actually there is a more comprehensive survey coming out from Ofgem that perhaps has some slightly different numbers. Clearly, we are in a different position than some of our competitors as a result of the cost that we have managed to take out of the group. I think also some of the retention rates that we are managing to achieve through a higher level of service and our online and greater online penetration is giving us better than industry average profitability. Phil, perhaps you Just one build on that. Ofgem look at it in two ways. You look at it in the forward basis and also look at historical, where they have had BDO come in and do a historical audit analysis. The historical audit analysis has shown industry margins between 3% and 4%. That in 2011, I think they will show, they are about to produce the numbers, they will show that industry margins actually fell in 2011 versus 2010. What you are referring to is a forward projection that they use, and within that, they make certain assumptions about the model. For example, they take the average tariff price, whereas actually, a lot of tariffs are sold with discounts, dual fuel discounts, online discounts. So they do not take into any account the discounts. The second thing they do not take into account on their forward projections is energy efficiency. They are assuming a standard consumption per an Ofgem household that actually bears little resemblance today to the reality, because we have insulated so many homes across Britain, and that is why systematically, that model overestimates the margins, and it is something we have raised with Ofgem, and they have acknowledged that they need to equalize the reality of the actuals with these forecast margins. It is not entirely helpful. Just to build on Phil's point, you frequently see media commentary of average bills being GBP 1,350 or GBP 1,400. The actual average British Gas bill for 2012 was GBP 1,188, and that is the result of customers going online, having dual fuel discounts, having direct debit discounts, and a number of other measures and people being on fixed price. So actually, there is a significant difference, if you like, between the numbers that Ofgem use to calculate margins and the numbers that actually we see in the bills. Okay. Thank you. On expectations, Mark, consensus for this year for BGR is around GBP 600 million. Obviously, it is very early, but we are comfortable with that at this stage. Wow. Right. Ed, we will start with you and then work across. Edmund Reid from JP Morgan. Two questions. The first one on non-commodity costs in British Gas Residential. They seem to have risen quite a lot in 2012. Clearly, with ECO and distribution fees, they will probably go up again in 2013. Can you give us any guidance on what that would look like? Yes, and I think you should have in front of you, I have not got in front of me actually, the famous light bulbs, which show how some of those charges have moved. If and we are really specifically talking ECO, it would be in the green on the light bulb. That was certain CESP 2011 to 2012. In terms of 2013, we could expect just on the ECO program alone, another GBP 20, GBP 25 on the bill, basically, depending on where the costs come out. Obviously, going back to the earlier conversation with Lakis is that what we have agreed with the government is that there will be a midpoint review during 2013 to actually assess the value for money of this program. Our concern being that actually, if you look at this in terms of money spent on carbon abatement, this can end up being a very expensive program in terms of carbon abatement reductions, possibly well over GBP 100 to abate a ton of carbon. Okay. My follow-up question is, will you be able to absorb all of that increased cost via reducing your controllable costs, or do you think there might have to be a movement on pricing? Well, we will have to see. It will depend on the other variables on the bill, in terms of what happens to transportation and distribution costs, but also very fundamentally, what happens to the wholesale commodity cost. I think it would be tough to absorb an increase of that order of magnitude purely with operating costs. But equally, the point we make to all our customers is that actually, as a result of energy efficiency, even if unit prices were to go up, and I am not saying that they are, there is an opportunity to offset that with efficiency savings. Thank you. Very good. I'll go back across here. Jamie Tunnicliffe from Redburn. Ed, I think not that long ago, you were talking potentially of investing or willingness to invest maybe up to GBP 1 billion in the GBP 2 billion Race Bank project, and I think as you said, you're now talking about a figure no more than GBP 200 million. It seems to be an area that you're saying you're willing to commit less capital to offshore wind in the U.K. going forward. Could you just maybe talk about that and why that change is coming through? I think as we look at the offshore wind regime, which as I indicated, is under transition, and we'll talk about it more in the second session. I think we are with the phasing out of the ROC banding, clearly, the returns, the revenue is coming down, and actually we're not seeing, unfortunately, with the tapering of relief, lower revenues on the income side, and we're not seeing a corresponding reduction in unit costs, because although the turbine efficiency is increasing, we're moving into deeper water and we're further away from the grid. So the economics are not that attractive. Now one of the things we're also, of course, working on is there the opportunity for some transitional CFD mechanism, which, if successful, could possibly allow us to put more leverage into the wind operation because the investor is then not just taking the wind risk, but is also no longer taking any of the power price risk under the CFD proposition, and therefore, that enables slightly higher leverage. But I think when we compare the amount of capital that's required for wind versus what it does for us strategically and what it does in terms of the returns that we get with opportunities that we've got in other parts of our business, in the gas value chain and in North America, it's not as important a piece of the strategy as we would have envisaged a few years ago where we saw returns higher. Yeah. Please. Yeah. Morning, it's John Musk from Royal Bank of Canada. On BGB, can you give us some indication of how you expect to turn around some of the declines that you've seen in that business, and where margins might go there? Is there any reason to assume that they will be any different now to residential energy? Secondly, and forgive me a little bit on this one, the list of strategic priorities that you've run through, there's only ticks there, in terms of what you've done over the past few years. Are there any crosses that should be on the list? Both very good questions. Let me come to BGB because you would actually say that probably BGB in 2012 was a cross. In that clearly with the more depressed economic environment, we had a lot of retailers in particular who were closing down or going out of business. But we also lost some customers because we actually don't think we have as competitive a model, and we haven't got the costs where they need to be. So we are in the middle of a significant systems upgrade. We made the big investment in SAP systems a number of years ago for BGR, but we forestalled it for BGB, so we don't have the SAP systems that we have for BGB. But we are in the process of putting those in place, and they will be in place by the end of the year. That is a major systems upgrade onto SAP, what we call our Slingshot project. That will actually enable us to take significant cost out of the business. Where will margins end up? I think in this environment, it's realistic to suppose that with the economy where it is, that I think margins are going to remain relatively tight in this business. But we think we can get back to growth over time. What we're signaling is that 2013 will be a year of consolidation, and then growing from then on. In terms of other areas where I think we would have wished to do better. I think we've had strong growth in the services business. I think we would have liked to have done more of the cross-selling too, and that's something that is going to be a key focus area for the new organization going forwards to see if we can increase the bundling between services and energy. We're just completing the systems upgrade, which is our Catalyst project, which you may have heard us talk about before, which actually enables all our call center agents on a single screen to actually see the account of a customer and with a very clear series of scripts as to what products to offer the customer. I think that will start to hopefully increase the cross-sell. That program probably took a little longer to roll out in BGB than we would have liked. In the upstream, as I've already mentioned, I think the tax hit was a significant hit to the business in terms of the upstream overall. I think in North America, the Ontario market, and the closure of the Ontario market to competition clearly has been a drain on the business, as has been the collapse of the wholesale price as a result of shale gas. That's something I think that we've adapted our business to and are now moving forward from. At least one cross. The other thing I think I'd comment on is we actually refer to it in the opening script is, for all the good that the business is doing, we have yet failed to persuade the media that energy is very important to this country, and that the contribution of this particular company is an important constituent part. You will probably see it at the weekend, the results of the work was done in Oxford, where we are seeking to ensure that the people do understand that this is a real force for good and it's not a rip-off industry. I think we've got a long way to go. It's certainly something we can mark out of 10 this time next year. Okay. Thank you. Bobby. Yep. Thanks. It's Bobby Chadha from Morgan Stanley. A couple of questions. The first one is directly related to the comments you just made. Without trying to predict what your tariff increases are going to be, it does seem pretty much certain that unless commodity prices fall substantially, all the other factors mean you have to keep putting prices up. It seems like the political and regulatory backdrop. Even if you put the press to one side, has deteriorated a bit. No one seems to be admitting that the reason for retail prices rising is not your margins or commodity prices, it's other factors. Maybe this is part of your strategy, and we'll hear about it at 11:00 A.M., but how do you propose to manage that risk? Because it seems to me to be bigger than it has been. I think, Bobby, you're on a very good point, and if I take that question, then we'll come back to others. But in a world of low economic or no economic growth and lower disposable income, it's natural that this is going to be a tough message for us to get across and for politicians to get across. What we're doing about it is, on your British Gas bill now, you see what's in the light bulb, basically. So that our customers, I think, are increasingly aware of what the drivers of the bill are. And whilst nobody likes it, I think people are starting to understand it. I think there has been a bit of a sea change. Actually, you don't possibly see it when you pick up the tabloid press, but when you actually talk to customers, I think we're not seeing some of the hostility because I think people are actually starting to understand what is in the bill, but this is an education. In an environment where you've got a large sector of the population who work in the public sector, who've got 1% pay increases, and you've got another sector of the population who are on benefits who are also going to get capped at 1% pay increases. You've got 60% to 70% of the population capped at 1%, and you've got bills, not just for energy, but for lots of other things going up by more than that. That's a general tough message. But I think the other piece of the equation is helping people understand that we have to invest to keep the lights on. Obviously, you saw the regulator's comments last week. The message about the need for investment is also getting out there, and that message is becoming more urgent. But it's a continuous education, Bobby, and it's not easy. On upstream, you gave some three-year averages for success rates and F&D costs, but it does seem that 2012 was substantially worse than 2009, 2010, 2011, both in terms of success rates and also commercial developments. A couple of things were either late or lower flow rates. Can you give us some context as to why these are one-offs, and we should expect things to improve? No, I think that is a fair observation. Firstly, on exploration success, we had a couple of wells last year which both found hydrocarbons but not at commercial flow rates, which is very disappointing because they were quite significant wells, the Bligh well and the Cooper well. The good news is that actually 2013 has got off to a much better start. We have had two discoveries already this year, one in Norway and one in the U.K., which we will talk about. So I think that is positive, but it is in the nature of the exploration business. I do not know any company that has a continuous track record of success. You will have periods that are more successful than others. I think you have to look at it, measure it over the long term, and I think we still think our model is working and it is working well, and I think that is sort of validated by the recent successes that we have had. In terms of the bringing on stream new developments, you are absolutely right. I think we had a number of specific instances last year. The first one, and I think the most significant one, was the Ensign development, where actually we had mechanical difficulties drilling the wells. The reserves are still there, but we just could not drill the wells. That resulted in us writing off, and we took this through the left-hand column of our accounts, some GBP 70 million for Ensign last year. So that was clearly a disappointment, and I think that we have learned lessons around well completions, a more conservative approach to well completions. I think we were attempting to do this in the most cost-effective way, and I think those lessons have been learned. But Ensign is now producing, and it is producing at a reasonable rate, although we will not recover all the reserves that we had first hoped. The second area, I think, was genuinely not within our control, which was Seven Seas, where actually we had been working with the operator of the host platform, BP, for a number of years to try and bring that field on stream. They had a lot of mechanical engineering and, frankly, management challenges with the host platform. That resulted in that being delayed. I think what we did, Bobby, is recognizing those difficulties in the early part of last year. We set up a new project management capability called our PACE team, led by Sarwjit Sambhi. We brought in some very good people from across the industry to actually really strengthen our project management capability, and that is starting to deliver some very strong results. Now, I mentioned that our York development, which is due on stream literally imminently, I think is actually going very well as a result of the interventions by that team. Our Rhyl development, which is going to be bigger than we first thought in terms of reserves, is also going well. So I think we are on top of that problem, but I certainly acknowledge that in the first half of 2012, we had some issues. Mark, can I just- Yeah, Mark. The success or failure is quite lumpy in exploration. If you look back over the last three years, we've put in place 103 million barrels of 2C reserves over those three years through the exploration program. 2012 was lower. It was a bit disappointing. There was only 16 million barrels of reserves added as a result of drilling. Some corrections in terms of the overall reserve accounting, but with the drill bit, 16. As Sam said, the first two wells that we've drilled in 2013 have been successes. I think the track record is still a strong one. 2012 was a bit down. Moving across. Please. Thank you. Yep. Gus Hofstra from Europa Securities. Two questions, if I may, please. In the first instance, in terms of BGR numbers, a slight decline. Hitherto, you've put much store in smart metering, et cetera. If you could give us perhaps a little color of how you expect to arrest that decline, grow that number, and how that compares vis-a-vis the competition. Then rather more aimly, if I may please, the load factors at Lincs and also across your CCGT fleet, please. If I understood the first question correctly, was it around margins or customer numbers? Customer numbers, please. Customer numbers. Yes, you're absolutely right. We lost about 1% of our customer numbers last year. For the early part of the year, we weren't as competitive on price as we need to be. Since the last round of price increases, we've actually been adding customers. If you look at this year, we've been adding customers, so we're getting back to growth because our price increase, you'll recall at 6%, was lower than all our competitors. Actually, we are moving forward. I think it isn't just about price. It is also about service and differentiation through measures such as online, where I think we have a better offering. It is around the smart meter installation, which is also adding customers and helping retain them. It is increasingly around other energy devices linked to the home and the smart connected home, which we will talk more about in the second session. Phil, do you want to add to that? The only other thing to think about is the value of customers. We have seen SSE launch some very deep discounted offers, which actually they are now withdrawing, but in our view, those were likely to not create any value at all. So we look at the value of our customer base, and we know that if you have got a smart meter, if you have got services, then actually your likelihood to leave us is particularly low. If we take this year, we have been winning share against all of the big five. The only people we are losing share against are those that are exempt, the small suppliers who are exempted at the moment from the government and social obligations. I do not think that is a situation with increasing costs of those obligations that is sustainable for them, actually. As long as we are on a level playing field, we are very confident we can compete and retain high-value customers. To your second question, I think it is around the load factor of offshore wind generally and Lincs in particular. Mark, do you want to touch on that? Yeah. The load factor across the portfolio fell a little bit in 2012. We had 36% in 2011. We were at around 32% in 2012. That was due to some problems at Lid earlier in the year, some maintenance issues. We think this year we will be back up to around 36%, 37% load factor. I would say when Lincs comes on, we are expecting higher load factors from that farm, potentially up to around 39%. Thank you. Yeah, please. Ashley Thomas from Société Générale. Just a quick follow-up on Ontario. You have given us the context now for Ontario within DE Supply. Could you perhaps do the same for DE Services and just update us where we are with the Competition Bureau penalty? Well, clearly as a business, it remains that our services business in Ontario remains a much more significant business and is important business. On the competition inquiry, obviously we are participating and cooperating fully in that inquiry. It is not just us. It is launched against all industry participants, and we do not believe there is a case to answer, but obviously we will participate in the investigation. I do not think that there is a suggestion that even if the findings were to go against us, that this is going to be a very significant event for us. Is that fair, Grant? Any more? Perfect timing. All right. You have 2 minutes. 2 minutes, yeah. Yeah, Ian Turner from Exane. I have got 2 minutes. Maybe I can ask two questions. On the CERT scheme, I think lots of companies have been having trouble targeting the right kind of customers on the socially deprived side of things, and have not been able to do that. Can you just talk us through where you are on that? Yeah. Secondly, you have made some quite important decisions about management and new nuclear things over the past few months, and they all seem to have leaked into the press. I just wondered about if you had a comment on that, please. I'll deal with the first one. Obviously, we were disappointed about the leaks, and we will have an investigation underway to make sure it doesn't happen again. I think on the CERT scheme, this was a very ambitious scheme. We said at the time that actually when it was launched, it would be difficult for energy suppliers to find, not necessarily the total number, but actually some of the super priority groups to which you're referring, where even the government were actually having difficulty finding them themselves. I think, Phil, if you want to sort of touch on where we've ended up, but I think we've ended up in a good place and done a lot more than other suppliers. Yeah. Obviously, given our scale, we have the biggest obligation. If there's a finite number of super priority group, then we've got to work hard to get them. There were two schemes that ended at the end of the year, was CESP, which was community-based, and CERT, which was individual household-based. We've fulfilled our obligation on CESP fully and on CERT, there is a small delay between jobs that we've booked and actually having them fulfilled. There was obviously quite a rush at the end of the year. So we're confident that we will have fulfilled our obligation. It's a question of what leeway will Ofgem give us for the, if you like, the program coming to end. Now, our interpretation is that they will give leeway. For example, they were quite late in approving some of the schemes we did. So in fact, some element of delay there wasn't part of our management. I think the other element then of ECO, it's going to be the same problem and more some, because we've got to find, for example, under Affordable Warmth, boilers that have broken down, that cannot be repaired, that is a low-income family, and you've got to do it in a certain period of time. So you can just imagine those are the sort of golden tickets for us to try and execute. And that's one of the reasons why there is a discrepancy in our view of what it will cost, not necessarily to do the jobs, but just to get the leads to fulfill the obligation under ECO versus what DECC are assuming, and which is why we've got agreement that after six months, they'll step back and just look at, are we really getting value for money per carbon ton abated? Because all the easy jobs have been done, and so the cost of carbon abatement is going up materially in the ECO program. Just coming back to your first point, I think we'd also just make the point that on nuclear, the announcement about stock repurchases was kept completely tight. But the announcement on nuclear, we did have a lot of stakeholders to manage. And I think actually recognizing that this was very sensitive, we wanted to be clear with our partners, but also with the government and other interested parties what we were doing beforehand. And I think in those circumstances, it's always difficult to keep it tight. But you did not see the strategic presentation that you're about to see in The Sunday papers, so we must have made some improvement, which should encourage you to come back at 11:00 sharp. And thank you so much for the discipline of the morning, too. It's very good. Thank you. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation has now ended. This presentation will commence shortly. This presentation will commence shortly. This presentation will commence shortly. This presentation will commence shortly. This presentation will commence shortly. This presentation will commence shortly. This presentation will commence shortly. All right. Well, welcome back everybody. I hope you are all suitably refreshed in Goldman Sachs' hospitality. I think this is really the exciting session where Nick and I set out the future energy landscape. Talk a little bit about how it's changed, because there have been some very fundamental changes over the last three years, and what we are doing to reshape our strategy to adapt to that new landscape. I think as you heard in the first session, we have made good progress against the strategic priorities we set out three years ago, but much has changed since then. Three years ago, there were high hopes that nuclear, clean coal, and dedicated biomass would make substantial contributions to the generation fuel mix. Despite the long-term possibilities of these technologies, it is clear that natural gas now will continue to play a more important role in backing up intermittent wind, keeping the lights on, and heating our homes. In the next few slides, I am going to outline some of the trends that we are seeing in our market environment. In the U.K., where gas is used to heat 81% of Britain's homes, we will continue to see some consumption savings in the short term. However, the measures to deliver these efficiencies are, as we talked about earlier, becoming more costly. Offsetting these savings in domestic consumption, gas-fired power plants will be needed to back up increasing amounts of intermittent renewable generation. In the U.S., industrial gas demand is forecast to grow, and gas has now become a more important part of the power generation mix. In fact, U.S. carbon emissions have reduced by more than any other region in the world, largely as a result of coal to gas switching. With greater gas dependence in the U.K. comes greater import dependence as North Sea production continues to decline. U.K. shale gas may eventually contribute to the supply picture but will not replace either in time or in scale the need for increased imports. The U.K. now imports 50% of its gas. Import levels are expected to rise to almost 75% by 2020. It is worth bearing in mind that just under a decade ago, the U.K. was a net exporter of natural gas. Much of the growth in imports is going to come in the form of LNG, represented by the light blue section on the chart. Capturing the value in the LNG chain will become increasingly important for us. As you can see on the left, the U.K. will have to compete for supply in an increasingly global LNG market. LNG demand almost trebled between 2001 and 2011, and the number of countries that compete with the U.K. for imports rose from 12 countries to 25. On the right, there are huge variations in prices between regional gas markets, all driven by different factors such as the liquefaction and shipping costs, different fuel substitution possibilities, and new trends such as shale in the U.S. and, of course, growing demand in Asia. These large price differentials offer significant arbitrage opportunities to capture value. In the U.S., the big story, of course, is shale gas. As you can see on the chart, it now forms around a third of U.S. gas production. In the next few years, domestic production is forecast to surpass domestic demand. The market now has greater certainty about the scale and enduring nature of shale gas in the U.S., underpinned in part by developments in technology. This significant growth in shale production also opens up the potential of LNG exports. Many projects are in the planning, approval, and design stage. One so far, at Sabine Pass in Louisiana, has received all regulatory and government approvals. By the end of this decade, if politics permit, the U.S. could be exporting material supplies of gas, some of it potentially to the U.K., providing a competitive source of fuel for our customers. In U.K. power generation, we currently face the twin challenges of low spark spreads and regulatory uncertainty. Reserve margins are expected to tighten over the next few years, but this is unlikely to drive much upside in spreads in the immediate future, with plenty of generation capacity still online. As a result, the economics of new CCGT investments will depend on the nature and level of capacity payments, which still remain unresolved. Looking to renewables, offshore wind is still an emerging industry, and the costs have not come down by as much as many hoped. Improvements in technology and scale have been offset by planning delays and the added complexity of projects as they move further offshore and into deeper water. Future wind projects will be constructed under a new contract for differences regime rather than the existing ROC regime, and that means that investments will no longer provide a hedge for downstream volatility. If we add to the regulatory uncertainty the financing constraints for the industry, this makes for a less optimistic picture for offshore wind than we were looking at three years ago. In downstream, the picture is one of contrasts. In the U.K., the continued economic downturn is putting pressure on all forms of consumer spending, and affordability is high on our customers' agenda. Although energy efficiency has had a positive impact on bills, nevertheless, average energy bills have been increasing by some 4% per annum or, adjusting for weather, some 3% per annum since 2008. Commodity costs have risen, but so have non-commodity costs such as CERT and CESP. The costs of carbon abatement are growing, and much of the low-hanging fruit has already been picked. Delivering our ECO commitment is likely to continue to add significantly to the cost of supplying energy for all the major U.K. energy suppliers. In the context of rising bills, maintaining customer trust is going to remain a key issue. Energy efficiency and new technologies to help customers understand and manage their energy bills are increasingly important. In the U.S., the downstream picture could hardly be more different. Consumer sentiment is improving, bills are falling, and there's a more benign environment. The size of our addressable market is growing. 8 million customers have moved to competitive retail tariffs since 2008, and businesses are increasingly interested in demand response and energy management services, both of which we have the capabilities to provide. To summarize, the landscape has changed. Gas has become more important, and many of the opportunities will be in LNG and unconventional gas, mostly in North America. Regulatory uncertainties in power generation persist. Downstream, the opportunities to leverage our capabilities and scale on both sides of the Atlantic are greater than ever. To meet these new challenges, we're refreshing our strategic priorities. Downstream, we will innovate to drive growth and service excellence. Upstream, we will integrate our natural gas business linked to our core markets with a focus on the Atlantic Basin. Across the group, we will increase our returns through efficiency and continued capital discipline. Our vision is unchanged: to become the leading integrated energy company with customers at its core. In a minute, I'll talk in detail about these strategic priorities, but at a very high level, here's what they mean. Downstream, in terms of innovation, we will share technology systems and new customer propositions across the Atlantic. We will build on our leading propositions to deliver growth in B2B and services and in the competitive markets of the U.S. Upstream, we will invest for value in E&P, notably in North America, and limit capital employed in power. We will increase our presence in LNG and grow in our optimization activities, linking our positions along the gas value chain. Across the group, we will drive operational and cost efficiency, deploy our balance sheet capacity where we see value, and return surplus capital to shareholders. In order to achieve these strategic priorities, we're introducing a new organizational structure. Downstream, we'll create one international business. This will enable us to share ideas, expertise, and best practice across our markets. We can harness our growing technological capability in online smart meters and services for the benefit of customers on both sides of the Atlantic. We can leverage scale benefits in systems and operations in both the U.K. and U.S. Upstream, there's a real opportunity to bring together the top-class teams and technical ability we have from both Aberdeen and Calgary. With one international business, we'll be able to deploy our skills in seismic imaging, reservoir management, well technology, project management more cost-effectively across both opportunities. We will invest capital where we see the highest returns. This will be a single business with a single production target. We have a lean international functional organization to leverage scale, systems, and technology and share best practice across the Atlantic. This will involve changes to our senior management team, as you heard earlier this morning. After seven very successful years at the helm of British Gas, Phil Bentley is going to be stepping down in June. Chris Weston is going to assume responsibility for all U.K. and North American downstream operations. Chris has had an exceptional track record, having transformed our North American business. As many of you will know, prior to that, he ran our U.K. services business, and before that, BGB. Chris is therefore, I think, uniquely qualified to lead the new international downstream business. Mark Hanafin will lead our international upstream business with responsibility for E&P, both sides of the Atlantic, having successfully grown our upstream business in the U.K., Norway, and elsewhere. It's the natural next step that he should assume responsibility for our entire international upstream business. As some of you may know, prior to Centrica, Mark was at Shell, based in Houston, running Shell's global gas and power trading business. So his extensive midstream as well as upstream experience will be invaluable in helping us to grow the upstream business. The team are all here today. Some of you had a chance to speak to them earlier, and I hope you will have a chance after this presentation to continue the conversation. Now I would like to outline in more detail what these new strategic priorities mean for the group. Starting downstream, this new priority means delivering preeminent service levels in all the markets we operate and continuing to make cost efficiency a way of life. It means changing the relationship with our customers through technology to deliver products and services in a simpler and smarter way, and to capitalize on the growing demand for innovative B2B offerings. It also means growing in selected markets, particularly in North America. Our new organizational structure means we can cross-fertilize the best ideas and innovation to benefit customers in the U.K. and North America. Looking at the downstream business today, we already have large-scale operations on both sides of the Atlantic. We have 3.5 million residential customers in North America and nearly 16 million residential accounts in the U.K. We also have large-scale B2B supply activities. In fact, in North America, we already sell more electricity to business customers than we do in the U.K. And finally, we have an exceptionally strong services presence in both the U.K. and North America. In addition to scale, we have developed distinctive downstream capabilities. We are leaders in customer service and efficiency, and our strength and scale in home and business services is unparalleled. Our innovation and application of technology differentiates us from our competitors, with the potential to transfer these across the Atlantic. And all these capabilities are underpinned by strong and reputable brands that span both sides of the Atlantic. In the U.K., our operations are delivering great service while relentlessly being focused on cost. Our average cost per account and subsequent margin is significantly better than competitors. At the same time, we have continued to improve our levels of customer service. This is evidenced by an increase in our net promoter score, and also customer churn rate that is consistently below the industry average. The high-performance level in the U.K. is mirrored in the U.S. Unit operating costs have reduced, reflecting synergies from acquisitions and organic improvements such as call center consolidation. And our net promoter scores are increasing in all areas, reflecting investment in our billing and service platforms and our range of products. Technology provides a further opportunity to differentiate and grow downstream. The world of smart, connected homes is a good fit with our existing digital presence and services capabilities, and an example of how we can apply technology to offer customers greater control. For example, we have already developed a remote heating control product that can be managed through a mobile app, and we are looking to develop other apps that can also allow customers to control other household appliances. And if you did not get a chance to see these on the display stand outside during the break, then I hope you will take an opportunity during lunch. Ultimately, these products will attract new customers to our brand, reduce our cost to acquire, aid retention in key market segments, and reduce cost to serve. Over time, we expect these activities to deliver a material contribution to operating profit, both in their own right and through the attraction and retention benefits that I have just described. We also see the potential to differentiate ourselves in B2B, both in the U.K. and North America. In the U.K., we've already started to make considerable progress on energy performance contracts, where we partner with major organizations and share energy cost savings, at the same time deepening the customer relationship. We've now been selected as the preferred contractor on seven EPCs, and we expect this to grow substantially over the coming years. In the U.S., demand response products, where customers modify their demand in response to electricity prices, are becoming increasingly popular. These are also opportunities in distributed generation, particularly in solar. The solar market is poised to grow rapidly in the U.S. over the next five years, given reduced installation costs and an increasing focus from businesses on energy efficiency. Again, all of these B2B opportunities will not just add profit in their own right, but will also help reduce churn and improve the margins of our existing supply business. North America is an attractive potential growth market for us. Downstream profitability has increased year-on-year with an improved return on capital, reflecting successful acquisitions and improved cost efficiencies. And we've developed a market-leading position. In residential energy supply, we are now the number one retailer in U.S. competitive markets. In business supply, we have over 400,000 accounts, and we're seeing fast growth, particularly in the small business segment. Our market-leading position in North America partly reflects our success in making acquisitions. We've developed an effective model of acquiring blocks of customers, integrating them onto our platforms, identifying and retaining best practice, and removing costs to drive synergies. As you can see on the left, the three energy supply acquisitions we made in 2011 are all making good returns. It's not just acquisitions that are helping to expand our customer base. In 2012, most of our customer growth was delivered organically, and we added some 200,000 customers in the U.S. Northeast last year. How much further can we grow in North America? Well, so far, we've really only scratched the surface. Retailers as a whole account for just over 20% of market share, while Direct Energy is the market leader in competitive markets with a 15% market share of those customers who've chosen to switch. There's still considerable scope for further growth, both organically and through acquisitions. We also continue to advocate the merits of expanding the overall competitive retail market through further deregulation. We also expect to see further growth in services as we leverage our considerable purchasing power and deploy our expertise from the U.K. We plan to build out the protection plan business, which also has the added opportunity of bundling and franchise extension. In B2B, margins have been good, and we'll continue to target growth in the small business segment in North America. If we add all this together, what does it mean for operating profit in both the U.K. and North American downstream? In British Gas Residential, we'll continue to drive operational efficiency and deliver high levels of customer service to sustain our profitability. BGR will remain an important but less dominant part of the overall group earnings. In British Gas Services, we have a good track record of profit growth, and we're targeting this to continue with high single-digit growth following the rapid progress we delivered last year. We aim to target new segments such as landlords and additional product sales enabled by the smart world. In British Gas Business, over the medium term, we expect to return to profit growth enabled by cost reduction, better retention, and growth in business services, which is a new revenue stream for us. In North American Downstream, we're targeting to double the profitability over the next three to five years. We'll do this through a combination of organic growth, bolt-on, and indeed, potentially larger acquisitions if these are available for value. In summary, with Chris Weston at the helm, we'll continue to lead with great service while relentlessly focusing on costs and utilizing our unique scale, systems, and services capabilities. We'll look to capitalize on the move towards connected homes and businesses, sharing knowledge across the Atlantic to offer simpler and smarter energy products and services for our customers. We'll continue to drive growth in our selected markets, most significantly in Texas and the U.S. Northeast, but also in B2B and services, both sides of the Atlantic. Turning now to Upstream, the second pillar of our strategy is to integrate our natural gas markets linked to our core markets across the Atlantic Basin. This will involve growing and diversifying our E&P portfolio, developing our midstream business to integrate along the gas value chain, and maintaining a low carbon but capital-light power hedge. Of course, we'll continue to deploy capital only where we see the greatest value. This will be brought together as the international upstream business under the leadership of Mark Hanafin. Over the past few years, our upstream business has grown in both production and reserves. We've increased our 2C reserves tenfold since 2009, leaving us well-placed to add further reserves organically. We now have a sustainable mix of producing assets, developments, and exploration opportunities, and a more geographically diverse spread, with Norway a particular success story. We've also expanded our technical capability considerably and now operate 30 fields in the North Sea and close to 5,000 wells in North America. This growth in production, combined with the British Energy and Venture Production transactions, has increased the level of vertical integration and brought us more in line with our competitors. We're broadly comfortable with our current level of energy hedge. Indeed, the comparative energy hedges of our competitors may reduce as many of the U.K.'s coal plants close. However, on a post-tax basis, there's still leeway to increase our energy hedge further should we find attractive opportunities. We have been able to reach this position partly due to the distinctive capabilities we've developed upstream. We've a proven track record in asset stewardship, maximizing the value of mature production hubs by enhanced recovery techniques and reserve additions. We've also delivered a series of attractive mid-size capital projects, continuously learning and improving as we do so, and we have a strong pipeline ahead. We have a track record of securing acreage and a strong exploration success rate in both the U.K. and Norwegian sectors of the North Sea. We've been able to create strategic partnerships, for example, with Statoil and also with QPI. In summary, we've developed distinctive capabilities in E&P. To illustrate our new technology and how we've been spending our capital, I'll just show you briefly three examples. Firstly, Norway. Five years ago, we had no presence in Norway. Now we have a resource base of nearly 400 million barrels. Norway is the fastest-growing part of our portfolio, providing around a quarter of our total production and generating significant EBITDA and cash flow. The business is now able to cover its capital requirements through its own cash flow. This has been achieved through value-enhancing acquisitions. The recent Statfjord and Statoil acquisitions are outperforming their double-digit IRR acquisition cases. We have a significant development pipeline in Norway with a portfolio of eight potential developments and had good success in exploration. Second example would be Morecambe. In U.K. waters, our stewardship of Morecambe is an example of our expertise in managing and extending the life of a strategic, though mature asset. Adjacent to Morecambe, Rhyl is the first gas development in the area for 10 years and is due to produce first gas within the next few weeks. Further success this year at Whitehaven will increase the Morecambe reserves still further. Morecambe is going to continue to be an important asset, producing for at least another 10 years. In Western Canada, we've built a strong onshore E&P business, doubling reserves since 2007. Over time, our activities have shifted from shallow gas and coal-bed methane to deeper and more valuable liquids-rich gas and oil. As a result, we've developed significant E&P capabilities, including in horizontal drilling and multiple-stage fracking operations. These have the potential to be applied elsewhere across the portfolio. These case studies are a testament to the distinctive capabilities we've developed upstream, capabilities which can be deployed across geographies as we manage and measure our upstream operations on an international basis. The chart on the left shows how global production profile looks until the end of this decade. This is, of course, subject to continued investment in maintenance and development, which we estimate to be around GBP 1 billion per annum across both the North Sea and North America. In addition, we will expect to invest about GBP 100 million in exploration. You'll see the near-term growth from developments is already underway, and we would expect double-digit returns on all our investments. With the expanding portfolio, we would also expect production levels to be lower risk, more geographically diverse, and less dependent on exploration in the near term. We'll therefore continue to deploy capital upstream, applying rigorous capital discipline and conservative commodity price assumptions. This could include the U.K. North Sea, but it's a mature basin with declining resources. Our focus here will be on getting the most out of current hubs and considering bolt-on acquisitions where they are a good fit with our existing portfolio. We'll also consider divestments of non-core assets with the ultimate aim of having fewer but larger quality assets in the region. The same strategy applies in Norway. However, the remaining resources in Norwegian waters are much larger in scale than the U.K., and as a result, production unit costs are lower and reserve lives are longer. Norway is likely to remain a key focus of our exploration activity in the coming years, and we'll also consider further acquisitions in the region linked to our hubs around Statfjord, Kvitebjørn, and Heimdal. In Trinidad and Tobago, we have existing production from the NCMA-4 field, and we are also currently in front-end engineering and design on the Block 22 project. The key here will be to maximize the value of our existing positions while capturing the exploration upside. The main focus area of growth for our international E&P business will be North America. We will look to opportunities to acquire both conventional and unconventional assets. Expanding our upstream natural gas presence will provide a physical hedge for our expanding U.S. downstream position. It will reduce our collateral requirements, and it will provide some optionality for the possibility of gas exports later in the decade. In an increasingly global gas market, it will also diversify both our upstream and downstream exposures to NBP. In North America, as in all our investments, it is not just about the quality of the opportunity, but also about the timing. How quickly gas prices will recover from a 30-year low in real terms is uncertain. But with gas demand growing due to coal to gas switching in power generation, an improving economy, and the possibility of exports, the balance of commodity price risk appears to be skewed to the upside. Equally, the market prices for assets are starting to better reflect commodity price fundamentals with less speculative activity and some early investors seeking to deleverage. We will continue to look for opportunities to expand our presence in North American upstream. However, again, only where we see value. Looking at upstream and downstream together, we have strong positions in gas demand, shown here in light blue, and gas production in dark blue. These you will be familiar with. However, we also have important midstream positions shown here in green. These include our gas storage facility at Rough. In LNG, we have both the Qatargas contract and regas capacity at the Isle of Grain. In Europe, we have supply contracts, for example, with Statoil and smaller midstream positions on the continent. In North America, many of our downstream retail positions are supported with pipeline and gas storage capacity. As you can see then, as a major gas producer, purchaser, and midstream operator, we have positions and capabilities along the gas value chain. Taken together, these create opportunities for optimization and additional returns through the midstream business. We have a core capability in managing price risk, shape, intermittency, and seasonal swing. In addition, we have a strong track record of managing and optimizing gas power and midstream assets. As gas markets become increasingly interconnected and our positions grow, we can see a clear opportunity to grow our optimization activities to capture further value. However, with the exception of gas storage, we do not see this as an area which will require significant capital deployment. In gas procurement and contracting, we have been successful in building relationships, entering into commercial partnerships, and forming partnerships with some of the world's largest players, including Statoil and our LNG contract with Qatargas. As LNG becomes more important to our core markets, we will look to increase our presence through additional contracting. Focusing on the U.K., compared to the rest of Europe, the U.K. has relatively low levels of gas storage. Our Rough asset provides over 70% of U.K. capacity. With the likelihood of greater price volatility as a result of increasing wind on the grid, also as the U.K. imports more of its gas, additional storage is likely to be required. We have two potentially attractive projects at Caythorpe, a short cycle project, and Baird, a seasonal project. We have already undertaken much of the front-end engineering work. But the near-term outlook for volatility and seasonal price differentials is currently too low and uncertain to proceed. We are therefore discussing the necessary economic framework with the U.K. government to enable new gas storage to be developed in the U.K. Turning now to U.K. power, the outlook for the market looks challenged for the next couple of years. Ample capacity is leading to the likelihood of continued low spark spreads. We will therefore continue to manage our existing fleet as efficiently as possible, positioning ourselves for any recovery in the market, which may start to tighten once coal stations close in 2015. As the market recovers, we would expect our output to increase. With our gas-fired power fleet, there may be opportunities to invest relatively modest sums of capital to cost effectively improve performance. For example, we have just recently upgraded part of our South Humber power station, and we have now approved the upgrade for the remaining units. Similarly, we will also consider closing our less efficient plant to maintain fleet performance. In existing nuclear, performance since the British Energy transaction has been strong, and there is now an expectation of seven-year extensions for the AGR fleet rather than the five years previously assumed. In existing wind, we expect to complete the Lincs offshore wind farm in the coming months, and financing is now complete. In summary, our existing power generation fleet is distinctive, with the lowest carbon footprint per megawatt hour of all the major generators. In new power generation, we will continue to maintain selective investment options, but we will only invest where we see sufficient value and have regulatory clarity. Although the EMR is making progress, both questions of principle and detail remain to be resolved to establish an investable framework. In CCGTs, we have options for new build, for example, at King's Lynn. However, decisions will be deferred at least until late 2014, early 2015, as we await both the introduction and results of an auctioned capacity mechanism. In offshore wind, the investment climate is challenging. Our approach in this area will be to be a developer partnering in the construction phase and cycling capital in the most efficient manner while managing the overall project risks. We have a strong pipeline with a decision on Race Bank due as soon as we get satisfactory economic framework and regulatory certainty. In the long term, this could be followed by our Round 3 East Irish Sea projects in the Celtic Array. In summary, in E&P, we have strong capabilities and attractive investment options to maintain production at around 75 million barrels of oil equivalent per annum. In addition, we will also look to invest where we see value, particularly in North America, as we move towards an international production target of 100 million barrels per annum. We'll also look to grow our midstream business to support our upstream and downstream businesses with a focus on storage and particularly LNG in an increasingly global gas market. In power, we will continue to develop offshore wind projects, but only on a capital light basis while maintaining our existing and new build CCGT options at least cost, leaving us well-placed for any recovery in the power market. With that, I think I'd now like to hand over to Nick, who's going to talk to you about our third strategic priority and how this all comes together from a financial perspective. Then I'll return to summarize. Thank you, Sam. Morning again, everybody. As Sam said, our third strategic priority is to focus on efficiency and capital discipline. Obviously, we'll look at everything that we've talked about this morning through that lens. Just starting with a chart that shows you the basic cash flow dynamics of Centrica. You might have seen this before. Our run rate EBITDA is now close to GBP 4 billion, as I mentioned earlier. We use just over half of that to pay interest, tax, dividends, and other items like pension deficit payments. That does leave us with around GBP 1.8 billion of free cash flow, which is a very strong starting position each year. Outside of the upstream business, our pure maintenance CapEx is actually quite low, around GBP 200 million in a typical year. But to maintain our upstream production at around the current 75 million barrels, including North America, we would expect to spend around GBP 1.1 billion a year, albeit with flexibility over timing, and some years being higher than others due to the timing of projects. That does leave us with GBP 400 million to GBP 500 million for investment in growth or return to shareholders. Our investment options, as Sam outlined, include additional investment in the upstream business, offshore winds, new build CCGT, and gas storage, or using the cash generated to fund bolt-on acquisitions on either side of the Atlantic. We have the flexibility to compare those choices with each other and with returning funds to shareholders and to invest where we see best value. Just to prove I was going to answer Lancaster's point from earlier, in addition to strong cash generation, we do have a strong balance sheet position. The debt to EBITDA metrics look exceptionally good, not much over one times, but that is somewhat flattering given the high tax rate we suffer. But on the after-tax cash flow metrics that the credit rating agencies look at, we are comfortably above the levels that they would expect from us. Despite the share buyback, the RCF to debt metric is set to improve in 2013, as I touched on earlier, as last year's acquisitions come in with a full year of contribution this year. If you do the maths that we were talking about earlier and build in the EBITDA growth, we would expect to have around GBP 2 billion of credit headroom by the end of this year. That does give us scope for additional investment, including more significant M&A opportunities. But of course, as we said earlier, each opportunity would have to be assessed based on its cash flow characteristics and its risk profile, with funding alternatives, including partnering, considered alongside that. As well as choosing the right investments to make, delivering the project successfully is key. There will always be challenges, but our track record is good and improving. We touched on some of this earlier, but the offshore wind projects have delivered well. We have had some challenges in the gas and oil side. Seven Seas did take longer, as Sam mentioned, due to delays by the host platform operator. As you know, the second well at Ensign was not a success. However, York and Rhyl are both on track to deliver first gas in the next few weeks, and Kew is on track for first gas later this year. We then have Valemon coming on stream in late 2014, and our largest single project to date, Cygnus, coming on around the end of 2015. As Sam set out, when you look across the portfolio, we have an attractive mix of upstream assets, exploration, development, and production, with good geographic diversity across different tax regimes. That enables us to high-grade our investment choices, adding to existing projects when there is a good timely return on the capital we put in. Just to bring this to life a little, I would like to look at some case studies. First two organic investment decisions, Cygnus and New Nuclear. Cygnus, first of all, as you know, a very substantial project, GBP 1.4 billion in total, our share being 49%. We did attribute some value to Cygnus in the acquisition balance sheet for Venture. Then of course, we had the tax hit, which does inevitably a drag on the accounting returns. But even so, and if you take into account the shallow water field allowance that Cygnus qualifies for, we still see full cycle returns for the project of around 10%. On a point-forward basis, returns over 20% at the time we took FID in the middle of last year. GDF are the operator of Cygnus, but we are closely involved, and the project has started well. In contrast, Nuclear New Build is a project we have decided not to participate in. I think as you are all well aware, judged against other projects and against returning funds to shareholders, the return profile of Nuclear New Build did not look attractive. We would have had to wait many years to see any return on our investment, and the project had become significantly larger than we expected as the cost increased. Clearly, we did not know exactly what the outcome of the CFD negotiations would be, but given the potential risks that were remaining, we knew enough not to continue to put in pre-development capital. I think this illustrates that it is not just about IRR when it comes to investment decisions, it is also about return profile and risk. I should emphasize that we continue to remain very happy with our investment in the existing nuclear fleet. As we said earlier, the output has been good and the life extensions are exceeding our expectations. Next, turning to acquisitions. The case studies here are the transaction we completed last year with Statoil in Norway and the First Choice Power acquisition in Texas. As Sam outlined, the Statoil transaction marked a step change in the scale of our Norwegian business with a specially tailored portfolio of producing and development assets. With the supply contract and exploration MoU, which we entered into alongside the acquisition, underpinning our long-term relationship with Statoil. The assets that are already producing, such as Kvitebjørn, reduce the risk profile and provide the cash and the tax capacity to cover the Valemon development. There are some quirks in the tax accounting which do hold back the initial returns, but the acquisition is immediately accretive. Returns do pick up when Valemon comes on stream, and overall, we are targeting a double-digit IRR from the investment. Second acquisition I want to look at is First Choice Power. Although a bolt-on in group terms, First Choice was a significant strategic move for our residential energy supply business in Texas, increasing customer numbers there by a third. The financials are also strong with a double-digit IRR, and those returns come early once the first-year integration costs are out the way. We value customer blocks like this on a blow-down basis, assuming all the customers churn off over a period of time. In practice, we look to do better than that, of course. As you saw earlier, our two other recent acquisitions of U.S. customer blocks are both outperforming their acquisition cases. There is scope for upside on First Choice as well, with the integration having gone smoothly and initial churn rates being better than we had modeled. Getting the most out of our existing assets and businesses will also be essential in delivering our strategy. There is always more to do, of course, but our operating standards are high, whether in operating offshore platforms or in distributed workforces operating in customers' homes. As Sam said, safety will remain a core priority, both process safety and personal safety, for our customers and our staff. At the same time, we must be efficient, controlling costs and reducing it where we can without putting safety, service, or compliance at risk. A year ago, we launched a two-year program to take out GBP 500 million of costs. As expected, half of the savings were achieved in 2012, and we are on track to hit that annualized run rate of GBP 500 million by the end of this year. Cost reduction ensures we remain competitive. For example, you saw from Sam how our cost base in BGR is lower than our competitors. It also enables to grow at times of limited top-line growth, as we are seeing with BGS at the moment, and to offset margin pressure, as we are seeing with BGB. It is also essential in acquisitions such as the U.S. downstream deals, where integration benefits are key to the financial metrics, and in upstream, we do have to offset the higher cost structure that will result from a shift in production mix away from legacy assets such as Morecambe. This cost reduction program will not end with this program, and we will seek to embed a culture of continuous improvement, ensuring we benefit to the maximum extent possible from our scale, the shift to customers dealing with us more online, and technology developments both upstream and downstream. Finally, we remain committed to ensuring that shareholders see the benefit of the superior returns in the business. The dividend is a key element of that. We have a strong track record of dividend growth over many years and remain committed to delivering above-inflation growth going forwards. The financial characteristics of the business give us confidence that we can do that, and our payout ratio and cash generation give us flexibility. In addition, as we have said, we will continue to benchmark investment opportunities against returns to shareholders. That led us to the GBP 500 million share buyback we announced earlier this month. We will maintain a strong balance sheet with credit ratings being important to our business, but where there are choices to be made on the use of funds, we will maintain the capital discipline we have demonstrated in the past. I will hand you back to Sam to wrap up before Q&A. Thank you, Nick. Let me just conclude. Importantly, our vision remains to be the leading integrated energy company with customers at our core. To achieve it, we have set out some new priorities and a new structure. As an organization, we will be able to share technology, best ideas, expertise, and innovation across the Atlantic. Upstream, we will continue to improve our positions through high-grading our North Sea portfolio, expanding our presence in North America, and maintaining efficient power station operations both in the U.K. and the U.S. Downstream, we will share expertise, technology, and new propositions across the Atlantic. We will grow in services and business to business. North American Retail will become a more material part of the group. Midstream, we will capture additional value by linking our positions, optimizing our assets, and having an emerging presence in LNG. What this means in practice over the next 3-5 years is that in the U.K. downstream, we expect stable margins in BGR, but with growth in both BGS and BGB. Our commitment to decarbonization through encouraging energy efficiency remains. To drive a new source of growth, we will build on our market-leading capabilities in online, new technologies, and connected homes. In North American downstream, we will continue with our successful approach of organic customer growth in deregulated markets and continue to look for bolt-on acquisitions. We will also consider larger-scale opportunities should we see value with an aspiration to double the size of our North American downstream business in the next 3-5 years. Upstream will continue to grow with new developments and exploration sustaining international production at around 75 million barrels of oil equivalent per annum. We will continue to build and optimize more of our portfolio on an international basis, and we will focus our investment on North America. Production will move towards 100 million barrels per annum globally should we see opportunities to invest for value. We will maintain our distinctive low-carbon power generation hedge but look to share the equity risk of any new major U.K. power investment. We will increase our presence in LNG and grow our optimization business integrating along the gas value chain, and we will retain our options to invest in power if we see value. At the group level, we will continue to drive cost efficiency while staying sharply focused on the safety and operational performance of all our operations. We will only deploy capital where we see value and continue to provide strong returns to shareholders, both through the dividend and through share buybacks. To conclude then, in the face of a changing market environment, our new strategic priorities build on our existing capabilities and position us for continued growth. Thank you all for listening. I think this represents a very exciting new chapter and also the new market realities that plays to the considerable strengths and capabilities that we've built up across the group. With that, I think I'd now like to ask my colleagues to come up and join me, Nick and I, and we will open it up to questions. Thank you. Hi, it's Mark Freshney from Credit Suisse. Just two questions. Firstly, on BGS and BGB, you had a similar strategy for growth that you presented three years ago. The growth didn't come through because of a weak economy. If U.K. disposable incomes remain weak, are you still sure that you can grow these businesses? I guess what I'm saying is what's different this time around? Just secondly, on many of the organic development options, such as, I think, the two CCGTs, the gas storage assets and the wind, how confident are you of being in a position to take these through to FID? Because it always seems, for example, with the gas storage assets, you had a robust case, then there was an issue with the TPA, then spreads came down, and then you needed support. It just seems that many of these options are just perpetually on the back burner. Two very good questions. Firstly, I think in terms of BGS and BGB, can we deliver the growth? I think actually if you look at the very strong growth in 2012, clearly we have delivered the growth despite a very difficult economic backlog. I recognize that a lot of that was due to cost reduction rather than top-line growth. I think what is different, looking forward, as we talk about the smart connected homes and as we talk about some of the new technologies we are beginning to deploy, remote heating control being an example, but also the smart-enabled world. Plus the fact that we are, as I indicated in the earlier session, I think now nearing completion of a very important project, the Catalyst project, to enable us to more effectively cross-sell, which did take longer than we'd anticipated. I think that's what's going to drive the growth in BGS. In BGB, I think actually, we're going through a major systems upgrade, as I indicated, new pricing propositions. A lot of the growth in BGB will come also from the services capability that we haven't had before. We bought some businesses last year, Connaught being one of them, to give us the services capability, and we're now offering services to our commercial customers, which we weren't previously doing. That is a new source of growth as well. I think your second question was around projects that don't really happen because the regulatory environment doesn't change fast enough. You instanced, I think, both gas storage and CCGTs. Obviously, we're not in control of the regulatory environment. Capacity payments are required for us to make the investment in new CCGTs. They are in the Energy Bill, in principle, but then there has to be detailed secondary legislation, then they have to run an auction. Then for us to invest, we would have to be successful in that auction. There is by no means a certainty that that's going to happen, and it's not going to happen quickly. I think that's one of the reasons that we're in this strategic refresh of putting more emphasis on gas and less emphasis on power. Gas storage, I think is a different situation where we probably have distinctive and the best storage proposals out there. The Caythorpe field, I think, has the best economics of any storage project that is waiting to be developed, but still not sufficiently good economics with what's happened to the compression of spreads that you heard about earlier. It is going to require some form of storage floor. Again, we're in discussions with the government. We've been in discussions with the government for a couple of years, as you rightly say, on this, and so far, I think there isn't a recognition from the government that that really needs to change, but we'll see. It is worth saying, Mark, you picked up the things that haven't happened, of course. Cygnus needed the Shell-led allowance. We got that and proceeding with that, it's a huge project. Lincs needed two ROCs. We were patient. We got that. That's why it's important to have options and choices. Yeah. Race Bank, we are in discussions with the government, and if we can get the right terms with the strategic partner that we have to invest in Race Bank, then it could happen at the level of capital we talked about earlier on. Yeah. In the back. Yeah, at the very back. Yeah, sorry. Richard Alderman, Macquarie Securities. Can I ask on this U.S. acquisition strategy, firstly, would you consider buying a company in excess of the $2 billion headroom that Nick talked about earlier on? If you are making acquisitions in the U.S., what sort of hurdle rates are you setting for that type of transaction? The second question, would you consider investing in biomass in the U.K. as a greenfield project or in any other JV partnership? Let me speak to the first one, and I'll also ask Mark Hanafin just to fill in on the story of biomass, too. I think in terms of the U.S., as Nick indicated, actually, the headroom is, to some extent, a function of obviously what cash flows we buy. I think certainly there's nothing planned to go beyond that, but it will all be very opportunity-dependent. I think we're not signaling here a sort of massive step change. But we are saying if you look at the acquisitions that we've done so far, they have all been a few hundred million dollars or less. In many cases, buying blocks of customers has actually been $50 million, $75 million. So what we're saying is we could do more than that, but I think there's no current intention to sort of bust through that headroom, and we do think that actually the A credit that we have is important to the group, and we will want to protect that. In terms of the hurdle rate, the hurdle rate on all our acquisitions is actually a pretty high one. The way you can think about this strategy, if you like, in terms of our financial profile, is that we will be doing less investment in organic power opportunities that might take a lot of pre-productive capital and reduce our ROCE in the short term, and actually doing more investment in gas production and in buying blocks of customers, which tend to be and will be accretive to earnings from day one. That will actually improve our overall financial position going forward. I think in terms of biomass, obviously we did invest in some money in dedicated biomass for our existing retiring CCGT power stations. Mark, you might just want to talk about why we decided not to continue with dedicated biomass. Just to put it in context, we We've had a clear strategy on what we're investing in in power. From time to time, we do a scan of all the different technologies, see what's changing, see if there are other investment opportunities, and that's where the biomass opportunity came from. We looked at it, we thought there were potentially good returns. We developed three projects for a reasonably small amount of money, but the three good projects that were viable dedicated biomass projects. Then, probably was it four or five months ago, the government came out with new bandings and essentially ruled out dedicated biomass. That wasn't the signal they were giving previously. It was what happened. It immediately effectively killed off those projects. As I say, it's part of our business development. It's not a big setback. It's something we look at, we work on, and we see if we can make it work. I think in terms of your other part of your question about would we invest in a joint venture in some other kind of biomass, co-firing with coal, for example. I don't rule it out. I think these are all things that we look at from time to time. On the other hand, by definition, it wouldn't be us that we're operating that. It wouldn't be our capabilities that were being deployed, and it would be more of a financial type investment. I think we would need to try and understand why that would make sense. Very much on HSBC. Just a question about, I think, politics in the U.K. Your new strategy seems to show a lessening commitment to U.K. electricity market. Thus far, you've had a balance between a commitment to invest, particularly in power with new nuclear, which has now changed. Do you think that increases the political risk on your downstream businesses now that you appear to be focusing more on the U.S.? I think there is some shift from power to gas, but that is for a consequence of the political and economic realities that we are facing, and that's why I spent a little bit of time on the landscape at the beginning of the presentation because, Electricity Market Reform to actually turn into an investable proposition is still 2 years away. There is no doubt that the regulatory framework, I think, is still uncertain. So I think we have to acknowledge that, and we also have to acknowledge that anything that is dependent on subsidies for low carbon is not without political risk. So we are shifting some of the investment from power to gas, and more than if you like shifting from the U.K. to outside the U.K., and we'd be doing a lot in gas if we look at not only our Cygnus project that's underway, the York project that's underway, but some of the projects we're doing in Norway that actually bring gas to the U.K. Question at the back. Hi, it's Peter Bisztyga from Barclays. I was hoping for a little bit more color on your North American growth opportunities. Could you give some indication of how much of that doubling in EBIT that you're forecasting will come from M&A and how much is going to come from organic growth? Then just a broader question on North American M&A. When you talk about larger scale acquisitions, are you talking purely customer bases, or are you thinking about any kind of physical assets in there? Similarly, when you talk about growth opportunities in LNG and midstream gas, would you consider acquiring pipelines, LNG tankers, export terminal capacity? So any color on that would be gratefully received. Thank you. Yeah. Firstly, I think in terms of the doubling the downstream profitability, the way we think about this is we will have, I think, good, strong organic growth, which will probably get us a third to maybe 40% of the way there. The rest of it will come from acquisitions, which could be a series of small acquisitions, or it could be something larger. I think in terms of whether those acquisitions include assets, and this is putting aside the upstream business, I think this is very much about continuing to buy blocks of customers. In the LNG and midstream world, as I mentioned in the presentation, we expect this to be largely a capital light operation, contracting for LNG, contracting for whether it is liquefaction capacity or whether it is for ships rather than putting them on the balance sheet. It is intended to be a capital light model. We already have, of course, a capital light model for regasification facilities at the Isle of Grain, and it's a logical extension of that. Lakis. Lakis Athanasiou, independent analyst. First, a general question about the U.S. E&P. Just trying to understand your rationale behind that. Is it about integrating into the U.K., in which case, buying reserves with production greater than any LNG processing capacity you could get at some stage, your production would have to be below that? Or is it about both that and also a pump on recovery in North American E&P? A second question- Maybe we'll do that one first, and then we'll come back to this one. I think, as I attempted to explain in the presentation, it's multiple factors. It is providing gas for our U.S. gas customers, which are a growing number, and of course, it reduces the collateral we have to post for those U.S. customers. It is a view that actually, over time, the value of those reserves will go up. And it is the, over probably greater time, the optionality that that will provide if exports start to happen at scale. It is the three components. Okay. Our next question is chart on page 36. I had a little bit of difficulty understanding it. You are showing a top profile remaining at 75. You do not seem to be showing all development of all your 2P reserves, the big ones like Maria and Olympus. The yellow, which is the I cannot see that coming from anything that you have got currently. I kind of see that coming from acquisition of producing reserves. In other words, you are not going to hit those targets or get any of that production beyond the orange and the green and the blue unless you acquire producing reserves. Would that be a correct interpretation? That is not a correct interpretation. That is things like Maria and the Butch development in Norway, together with Trinidad and Tobago, too, and Block 22. That is in the yellow, and that is what effectively sets the- That is not going to come in before 2016. So it is only after 2016 I am talking about. Some of the Norwegian will. Some of the Norwegian will. Yes. That is the- The big step-up post 2017, 2018 is Block 22 coming in. Absolutely. Prior to that yellow area is basically a very large portfolio that we have of development projects and taking a risking of that and applying it to give you an assumed profile because we do not know which project we will take FID on. It is a combination of what we have got in the existing Centrica Energy portfolio and a combination of what we will drill up and start producing in North America. It is not acquisitions that are in there. I will take that up later. Okay. We are happy to do that. Okay. Martin. Hi, Martin Brough from Deutsche Bank. Could I just ask about the change from the regional to the functional reporting relationships? National Grid seemed to go down that route six, seven years ago and struggled to communicate to local people that the businesses were being run locally with local resources and contributing local value, and they seem to have gone back to a regional reporting line. You have already communicated your frustration with maybe the U.K. media understanding the contribution of the company to the U.K. Isn't that going to get harder to communicate under the new structure? It just seems to me like the head of British Gas should be spending maybe all their time thinking about the customers, the workforce, the politicians, the new regulators, European Commission. That seems like a full-time job, not a half-time job. I think you raise a good point, Martin, but let me explain perhaps in a little bit more detail as to how it is going to work, and that is that this is not a move to a sort of complete functional organization where, for instance, you have global marketing and you have global back office, and you immediately have a whole series of global functions. We will still keep the head of North American Downstream. Badar Khan is moving into that position. He is very capable and has run actually BGB in the past, but he is currently based in North America running our upstream business. North America, if you like, will be one report rather than a series of reports to Chris Weston. British Gas Residential, run by Ian Peters, will remain as British Gas Residential, which really is the sort of customer-facing piece. British Gas Services, run by Chris Jansen, will remain as a separate business, and BGB, run by Steven Bennion, will remain as a separate business. So actually, you can think of it as those three people are really the local face of British Gas. This is not eliminating all the regional requirements as a true functional model would. It is a little different in the upstream, where actually the opportunities to leverage technology are greater, and therefore, I think we will see more cross-fertilization. Can I ask then, when the new regulator wants to see the head of British Gas, who will they meet? They will meet Chris Weston. Right. Yeah. Ed. I think Bobby is going to try to get a question in. Hi, Ed Reid from JP Morgan. Two questions. The first one is on the scope of energy efficiency for business customers. I think you mentioned it in the presentation. I just wonder if you can give us a bit more detail. Following on from that, you seem to be quite bearish on spot spreads in the U.K. despite the reduction in some of the coal capacity. Is that a view on demand potential in the U.K.? I said two questions, but I guess this is my third, is around upstream in the U.S. Obviously, you've given some more detailed numbers today about what you'd like to do there, but my understanding is that you've been looking at upstream, certainly conventional upstream, in the U.S. for quite a few years now, and that you've always found prices quite rich. I'm trying to work out your signaling today. Is your signaling that you're more positive on how much you're willing to pay because of the power price or because of the gas price environment? Or do you feel that prices in the market have now come back to a level that you're more comfortable with? Why don't I take your second two and leave the one on BGB for Phil. But in terms of spark spreads, I think that we are not bearish on spark spreads, but I think we're naturally cautious on spark spreads. We don't see the economy growing rapidly. Obviously, there will be retirement of plant, and some of that has already started to happen. For logically, you would expect spark spreads to improve over time, but we're just saying, this could take a little while when other people will possibly be doing what we're doing at Humber in terms of upgrading old plant rather than building new plant, and that obviously has an impact on spark spreads. I think, we do see the trajectory long term as being positive, but we're a little bit more cautious about it, perhaps, than some people who've got a bigger exposure to it who might be naturally a little bit more optimistic about it. I think in terms of the U.S. upstream opportunities, and yes, you're right, we've been looking and cautiously investing in upstream in the Wildcat Hills area as an example. I think two couple of things are happening. Firstly, I think we are, although not expecting a rapid recovery in Henry Hub prices, I think we're sort of pretty close to a floor here. As I said, I think we can see more upside probably than downside going forwards. But also, we are seeing value starting to emerge, particularly in properties that have significant liquids production, which provides near-term earnings enhancement. I think we're not rushing to do anything against the clock. We'll only do it if we can find value, but I think we are starting to see more value emerge. On the slide, I think we put up, we're showing actually there's been some compression of multiples. If you look at the transaction values per acre, they have been coming down, particularly in certain plays as one or two of the early investors who got in and got over-leveraged and over-enthusiastic are starting to try and dilute their positions. Phil- Yeah, on BGB, we see there is quite a big opportunity actually, Ed, because you've seen a lot of investment in the home, but very little in businesses. We have a Green Deal for domestic properties, but one of the things that's mooted at going forward is a Green Deal for businesses. For example, at the moment, if you're a Westfield commercial landlord, you don't have each retail site monitored for energy. So everyone leaves their lights on, and it's just embedded in the rent that you pay. That's going to change going forward, and I think there's going to be much more pressure put on commercial properties to think about how they reduce their energy consumption. We're already finding through smart meters that we can give our B2B customers advice that said, "Look, you close after 5:00 P.M. on a Friday, but you've used this amount of energy over the weekend because you've left the car park lights on or you've left the heating on." So I think there's some big opportunities there that we're just beginning to scratch the surface of. Three years ago, we had no sales in that space. 2012, we had GBP 204 million of sales. So I do think there is more to come in that field, and we have a team working on Connected Homes, and Nina Bhatia, who's at the back of the room there. She's also going to be looking at Connected Businesses as we go forward. Thank you. Bobby. Thank you. Could I go back to slide 36, please? I just want to make sure I understand the return versus profitability dynamic. There's a sort of danger of double counting, I think. If I understand it properly, you'll invest around GBP 1 billion per annum to keep at 75 million barrels of production. And you'd expect that billion of incremental capital to deliver returns well in excess of 10%. But thinking about it from the P&L perspective, isn't it fair to say that operating profit you derive from these assets is likely to decline in a stable commodity price environment? Because the new assets are more costly to run than the existing assets. Or is that too conservative? Well, interestingly, if you look at it on It's a question also whether you look at it pre-tax or post-tax because if you look at the Norwegian assets in terms of their unit costs, they would actually be lower than a lot of the U.K. assets. But of course, they are highly taxed, so you have to factor that into the equation. You will see, certainly from the U.K. portfolio, a rise in unit costs from the existing fields, but also the new fields as they are brought on stream will be higher cost and therefore lower margin. So there will be some margin compression there, yes. Looking at the same kind of slides that you showed us a year ago, or a little bit more than a year ago, for 2013 This slide compared to slides we showed you previously includes North America Yeah which is 10 million barrels represented by the red line, I guess. It's a slightly different slide you showed at your Yeah E&P Investor Day in December 2011, I think where there were two other fields due to come on this year. Annabel East, is that being pushed back? I don't think you've mentioned it at all today. Yeah. It's still there, but it's being pushed back. Actually, I think we're now targeting 2014, if my memory serves me right, for Annabel East to come on stream. My last question, sorry. Lots of people seem to be chasing U.S. assets, particularly ones with liquids, because they're obviously much more profitable. What is it that you think is your edge in North American E&P versus many other buyers? Well, I think we have this is not, as was identified earlier, this is not a new search, if you like. We have been going through a number of properties both in Canada and in the U.S. I think we have good subsurface skills. I think we have the capability of actually with the horizontal drilling and fracking that we do, and we have seen that with Wildcat Hills, which is one of the reasons I put it up as an example. I think we have actually got some skills there. Yes, it is a competitive market, but I think the market dynamics have changed a bit because some of the early investors who piled in when gas prices were very high have obviously found it difficult because they, as I said earlier, got over-leveraged. Yes, it will be competitive in North America. But actually we are still able, even in a competitive market, to secure negotiated transactions because we are regarded as a counterparty that people can deal with, and not everything goes out to auction. Okay, thanks. Yeah. In the front here. Ashley Thomas, Société Générale. It's being reported that you've retained Goodbody to look at the Bord Gáis Energy disposal. But obviously given the strategic, it would suggest that the focus for growing the residential supply business is North America. Is that a fair assumption of the strategic intent? Well, I don't think we can comment on specific opportunities. But I think that we would say that Ireland is a natural adjacency. So, it would be natural to look at anything in Ireland. But beyond that, I think it'd be inappropriate to comment on specific opportunities. Yeah. Jamie. Yeah. Jamie Tunnicliffe from Redburn. In the past, when you've talked about growing the customer base and the electricity customer base in North America, you've talked about then potentially having to do work on the power hedge against that. You don't seem to be talking about that. Is that a change in view in terms of that capital requirement, given now you're talking about a much bigger electricity retail base in North America than you were previously? Yeah. I think it is a change of view, and I'll let Chris speak to the sort of our views of the power market generally. But the full cycle returns of investors in the power sector in the U.S. have not been great. And I think we would have to have a particularly compelling case that was either underwritten by strong capacity payments that would actually give some certainty around near-term returns for us to want to do that. And I think we are more comfortable buying the quantity of electricity that we need on the open market in a world where shale gas is obviously ensuring that gas prices, although they may slowly move up, I think are not going to be subject to the same magnitude of price increases that we've seen previously. But Chris, maybe you talk about that. Yeah. The market has changed over the last three, four years with the reduction in price of gas on Henry Hub. At our current size, at the current commodity prices, the current liquidity that we see in the markets, and the volatility we see in the markets, we are very comfortable with buying the options, the hedges that we need on the market. If we were to grow materially or we see gas prices increase materially or more volatility, then there might be a case for some power generation to support the business. The most likely area that you would see that is in Texas, where you have slightly less liquidity than PJM or New York, and you have tighter reserve margins. So that would probably be the most likely place. But in the current liquidity, the current commodity price environment, our current scale, we do not need any more power generation. We can buy what we need on the market. Hi. Hi. John Johnson from Nomura. Just a quick one. I want to check my understanding of your expectations on returns from E&P CapEx, because we have got some examples of successful projects where there appear to be double-digit IRRs achieved. You are clearly targeting double-digit returns from developments. I am sure every investment case for the project has a double-digit return in it. But not all the projects are successful, clearly. When you look at it on a portfolio basis, and if we are thinking about our expectations on a portfolio basis, for your CapEx over the next years, should we be expecting double-digit returns on your investments? Or is it more realistic for us to expect a blended return that is some way below that? Yeah. I think you should absolutely expect. The point that was made in the earlier discussion around pre-productive capital versus productive capital, obviously lowering near-term ROCE. But if we look at the business without the pre-productive capital, we are in the mid-teens. If you look at all our new investments that we sanction, we should be well into double digits for any development because we have had a lot of that exploration expenditure behind us. If you look at full cycle here, we should be well in double-digit territory. The assets are shorter life, but it is materially higher return business than the power generation business on a full-cycle basis. Thanks. Yeah. It's Peter Bisztyga from Barclays again. In the U.K., a lot of the opportunity seems to be around energy efficiency. How confident are you that the revenue gains can offset the inevitable reduction in demand from both business and residential customers going forward? Well, I think we are pretty confident based on experience to date. I'll let Phil come back in on this. If you look at the growth of the services business, a lot of it, if you like, has been encouraging energy efficiency on the one hand, but actually the services business has gone from a business five years ago that was probably making GBP 150 million to GBP 300 million. So there's a big business in energy efficiency. Phil, you might want to speak to that. I mean, it's not just a swap between sales revenue and the energy efficiency margins. You've also got to look at churn because churn, as Sam showed on the earlier chart, is running at record low levels now. At the beginning of this year, the first couple of months, we've been running just over 6% churn, which when you think when I took over British Gas, we were running at 28% churn. That shows the progress that we've made. I think if we look at new-to-brand, how do we get customers back into our brand, then energy efficiency and all the new products is going to be the way. We've got some quite exciting new product launches to come in the next few months, and that's targeted not at retention anymore because we think we've cracked retention. It's targeted at new-to-brand acquisition. It's all part of how we grow the franchise of British Gas. Any other questions? One with Perez. Andrew Mead at Goldman Sachs. Following on from that, your Free Power Saturdays deal, one, why is that not an offer or a product in the U.K.? Two, whether or not it is or isn't, I prefer Sundays to be honest, rather than Saturdays. The second thing is on the outlook for the tariff simplification, does Ofgem's move mean you can't do that in the future? Phil, do you want to put a touch on that? Yeah. I mean, without giving all our secrets away, part of the reason why we look to run Downstream internationally is sharing those sorts of ideas. The key of Free Power Saturdays is you need a smart meter, and we've been successful. Chris and the team have rolled out smart meters in Texas. We have done 800,000. As soon as we get the volume up of smart meters, remember, we've done 80% of the country's smart meters, then that's what enables those types of tariff offers. Our belief with Ofgem is that they want to see innovation in things like time of use, and therefore there will be carve-outs within the strict four-tariff regulation coming out of RMR. We're obviously going to have to see the detail of that, but that's certainly our expectation that it wouldn't use a tariff slot directly. Two questions at the back, and then I think we should probably start to wrap it up. It's Ian Turner from Exane. Can I ask about the 20% stake in British Energy? Now that you're not doing new nuclear, does that still make sense as part of the group? Or if perhaps you're looking or you're recognizing that CFDs aren't a very good hedge, then perhaps a bigger stake than 20% in the nuclear stations will be a better hedge for you. Well, I think those questions are going in different directions. If we take the first one, actually what our stake in British Energy does, and I think is doing very successfully, is it does provide a low-carbon power hedge. It's obviously in the event that electricity prices do improve, unlike a CFD where the upside obviously gets given back through the CFD mechanism, our existing nuclear operations would perform better than they already are doing. The plant life extensions have obviously been very positive. So we're pleased with the investment. I think it's delivering good returns, and we want to hang on to it. Whether we want to go further in plants that are starting to age, I think is questionable. Chris. Richard Alderman, Macquarie Securities again. Quick question for the CEO. You rightly pointed out in your article in The Times this morning that there isn't a substantial shortage of gas coming into the U.K., so you partly answered one of the Ofgem concerns from last week's presentation by Alistair Buchanan. Could you perhaps outline what your thoughts are on the possibility of any form of generation price spike in the 2014-2015 winter that he also outlined, and the circumstances why you wouldn't agree with that, if at all? Yeah. I think what I was trying to say in the article is that we do need to recognize, as was said in this presentation, that we are going to be importing more gas, and we need to work hard to secure those new sources of gas. I don't want to, in any sense, suggest that we should be complacent about securing new sources of gas as the U.K. moves into greater import dependency and greater LNG dependency. But we think, building on the sort of relationships we've got with big suppliers, the Qataris and the Norwegians and others, and also if we continue to explore and maximize the recoverable reserves from the North Sea, that it should be a manageable problem. On the power side, our modeling suggests that given where reserve margins currently are, even though a considerable amount of capacity is going to come off the grid over the next 24 months, we think it's not such an immediate problem, perhaps, as the regulator was suggesting. Now, it's very sensitive, obviously, to demand growth on the one side, to weather, to individual days, and to how reliable, particularly the nuclear plant, continues to be. But I think we feel a little bit more confident over the next sort of 24 months, certainly, that load shedding can be avoided. But Mark, you might want to Yeah. The sort of big offer on this one is the forward market at GBP 1 a megawatt hour. It's pretty liquid out there, but that's what the forward market is saying. Ofgem sort of lights out, which would imply prices through the roof. I think our modeling suggests in the 2015, 2016 period, clean spark spreads of 4-6 sort of range. We need 10 for a cost of capital return on a plant like Langage. I think Sam's right to point out that there's no room for complacency. There's no room for any delay in terms of getting the legislation for capacity payments in place, and all of the other parts of the Energy Bill. But I think we have perhaps a more measured view of what the next three years holds. Does that model also include the 60 terawatt-hours from British Energy continuing for the next three years? Because I guess that's a one in seven year performance, and probably only twice in 12 they've done it. Yeah. I think whilst we would hope that continues, I think that's not in our base assumption. I think it would be fair to say that the considerable investment that went into the British Energy plant in the last few years prior to the sale, but also I think the operation of EDF subsequent to the sale, has delivered some material improvements, and we do expect those to be sustainable. But I think we wouldn't necessarily predict a record as our base assumption. Verity Mitchell, Agency. Just on terms of the share repurchase, how should we be thinking about that? Is that a one-off, or with the new strategies, are you going to stop, or will you continue perhaps to do it in future years? Let me take that one because I think it's an important point. Obviously, we're only just launching as of today our share repurchase, and we intend to complete that in the next 12 months. That's the immediate priority. But I think what we're saying, taking a three to five-year view, is we'll continue to measure organic opportunities and the headroom we have in the balance sheet. If we see the opportunities to do more of this, because either we have an inefficient balance sheet or we don't see the opportunities that are as attractive to our shareholders as stock repurchases, we'll continue to do them. It does say it on the slide, actually, the last bullet. I would suggest that if we have surplus, we will return it. Yeah. Okay. I think that's probably a good point to end on, but thank you all very much indeed for your patience and support, and we look forward to taking the next chapter of the growth of the company forward.

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