Earnings Call: H2 2013

Feb 20, 2014

Good morning. In a break with tradition for Centrica, I intend to make just a few brief introductory remarks and then join you in the audience and leave this presentation to Sam, Nick, and the team. As you know, these are early days for me, but I am pleased to have joined a company that is well-run with a clear, sound strategy. Yes, it is facing short-term headwinds, but I already feel reassured that with the depth of talent we have, these challenges are going to be tackled energetically and imaginatively. Of course, one such challenge is the political storm in which we find ourselves and which to an extent is understandable. It is no surprise that energy prices are a hot topic, and it is entirely reasonable that our politicians should be exercised about cost-of-living issues. We are. It is entirely reasonable that they should choose to echo our customers' concerns about value, service, and trust. These same politicians have a choice to make as they draw up their electoral strategies for 2015. Do they or do they not want a U.K. energy company of substance that is willing and able to invest on the international stage to secure long-term gas for the nation and at home to help remedy the imminent shortfall in reserve generating margins? In their rush to draw party lines, these politicians appear to have overlooked that Centrica's fortunes are inextricably linked with our nation's. That we supply energy and energy services to almost half the homes in Britain and nearly 1 million businesses. That we support 175,000 jobs in our supply chain, procure around GBP 10 billion worth of goods from 6,000 U.K. companies, and are one of the country's largest taxpayers and an important payer of dividends to our 700,000 individual shareholders and numerous pension schemes. With an eye on the trigger of the storm, I have spent much of my early days listening to customers, trying to understand for myself the issues of trust and the extent to which the steps we are taking to address these can work. Meanwhile, on the political front, I have been meeting with politicians, regulators, and officials with a view to restarting pragmatic, collaborative dialogues around the big issues that we face and putting an end to the polarized and disconnected relationships that currently prevail. There is just too much at stake. The invocation of broken markets and declaration of breakup intentions may make for good politics, but the unintended consequences for our nation's energy future threaten to be significant and irreversible for some considerable time. Most imminently, we are faced with trying to ensure that the conclusions and consequences of the current market assessment are to the greatest possible extent, independent and based on facts rather than politics. For sure, if it uncovers something that the previous 17 inquiries since 2001 failed to do, then we all should and will welcome a clearing of the air. The most important and immediate focus, however, should be on allowing the 19 different players, encouraged by the host of independent switching sites, to slug it out in a competitive market while giving the recently introduced retail market reform measures time to work. There's every reason to believe that the proposed quicker switching, greater transparency, and lively innovation will increase still further the competitive intensity of what appears to me from my early observations, an already very dynamic sector. For the benefit of our customers and for the nation's energy security, we are going to fight to see reason prevail over short-term politics. We're going to fight to restore the nation's respect for the role we play and trust in us earning the margins we do, starting with the people that really matter, our customers. Above all, we are going to fight to ensure that our performance maintains the progress that you've come to expect from Centrica. To elaborate on that key aspect, let me hand over to Sam. Thank you very much, Rick. I'm joined here as usual by Nick Luff, who will take you through the numbers in just a moment. Also with me up here on the podium are Mark Hanafin, our Managing Director for International Upstream, and Chris Weston, our Managing Director for International Downstream, who will both be available for Q&A at the end of the presentation. Much has changed since the first half results, particularly of course, as Rick's described, the political environment and the unprecedented focus of the energy sector in the U.K. We understand the very real concerns that customers have over energy bills. As Rick has just outlined, there's a pressing need for investment to secure the supplies of gas and power generation capacity that the country requires. At the same time, market conditions remain challenging for several parts of the group. With this in mind, the first of our key themes for today is around the robust management actions that we've put in place. We've new targets downstream to deliver better service, lower costs, and account growth. In a competitive market, operational efficiency and high-quality service are key differentiators of our business to be able to sustain appropriate margins over the long term. In upstream, we're targeting tight cost control together with reduced and refocused capital expenditure, which is essential to enhance returns on investment. Alongside these actions, the key transactions that we completed in 2013, the Sabine Pass U.S. LNG export agreement, the Suncor package of Canadian assets, and the Hess Energy Marketing acquisition, create platforms for long-term growth beyond the short-term uncertainties. This is going to enable us to underpin our competitive position through service and innovation, to realize the potential of our enlarged North American business, to develop our upstream portfolio, and to integrate our business along the gas value chain. Finally, as Rick mentioned, we're talking to all political parties. Firstly, to make them more aware of the strategic and commercial role that we play in securing gas and electricity for our customers. Secondly, to help them understand the makeup of the energy bill, something we pioneered together with our transparency of reporting. With that, let me hand over to Nick, and I'll provide more detail later on our strategic progress going forward. Thanks, Sam. Morning, everyone. As ever, I will start with commodity prices and weather. As you all know, gas prices were a fair bit higher in 2013, up nearly 15% year-on-year in the U.K., and by more than that in the U.S., albeit from a lower base there, of course. In contrast, oil prices were down year-on-year. The forward curve shown here, bottom left, suggests oil prices will continue to fall. For U.K. gas, the curve has flattened and recently fallen, whereas U.S. prices have risen on the back of the cold weather. Moving bottom right, outright power prices were higher in 2013 than 2012, tracking gas prices, but spark spreads were close to zero for the whole year, with no signs of recovery in the forward market. On the weather in the U.K., top right there, it was a year of two halves. Very cold in the first half, but close to normal, and hence a lot warmer than 2012 in the second. For the year as a whole, average consumption for British Gas residential came in unchanged. Against that backdrop, the group produced a solid result, albeit with no bottom-line growth. Revenue increased, the largest component of the increase being the expansion of U.S. B2B energy supply, including two months contribution from the newly acquired Hess business. Adjusted operating profit was down slightly, with pressure on supply margins in the U.K. and the U.S., offsetting higher profits from the expanded upstream business. Despite that, a lower tax rate and a lower share count due to the buyback meant the earnings only fell slightly, and EPS was maintained at 26.6 pence per share. With the balance sheet in a strong position and good dividend cover, we were able to increase the dividend ahead of inflation, pushing it up by 4% to 17 pence per share. Here on the screen, the breakdown of the operating result, and you can see the lower profits from British Gas and Direct Energy offset by the growth from Centrica Energy. Starting with British Gas here, profits were down 6%. BGR came in at GBP 571 million, slightly below the year before, impacted by the warm December, with the cold weather earlier in the year used to delay the passing through of higher costs, both commodity and non-commodity. BGS was up to GBP 318 million, benefiting from cost initiatives, and that was despite responding to 200,000 more breakdowns due to the cold weather in the first half of the year. The weak economy did impact contract numbers. However, we saw a recovery in installation volumes, which grew 10% in the second half. BGB saw continued margin pressure, in part due to our decision to end auto rollovers. Profits dropped to GBP 141 million as a result. Looking to 2014, we continue to target similar margins across the business. The mild start for the year will make it challenging for BGR, but there remain many variables that will impact the full-year outturn, weather and commodity prices in particular, of course. In North America, we saw pressure on margins in the residential energy supply market, and even more so in the B2B market. Direct Energy came in below our expectations as a result, down 11% year-on-year. The overall result from DE Residential was up to GBP 163 million, despite the expected decline in profits from Ontario and a lower contribution from Texas. The U.S. Northeast did well, helped by previous acquisitions, albeit with margin pressure seen there too, as gas and power prices rose in the second half. The $77 million DE business result was disappointing. Market conditions in power supply were challenging, with highly competitive pricing across the sector. We did have a Hess Energy Marketing business for the last two months, which is predominantly gas, of course, but its profit contribution was offset by deal and integration costs. In contrast, DE Services continued to perform well, with good growth in protection plan volumes and profits up to $36 million. The start of 2014 has been difficult for Direct Energy. The polar vortex has caused extreme weather and turmoil in wholesale markets, particularly in power, where balancing costs have been dramatically higher than normal. All energy suppliers have been affected, and we will see how the competitive environment evolves as a result. The short-term impact for us has been a hit of $70 million-$80 million, most of which falls in DE business. Taking this hit into account and the removal of power station profits following their sale, at current weaker FX rates, DE is now forecast to be broadly flat year-on-year in sterling terms, despite adding in a full-year contribution from the Hess business. Turning to the Upstream, Centrica Energy, now including the Canadian gas assets, came in at GBP 1.3 billion, up 6%. Gas production was up almost 20% and oil production by 7%, both driven by acquisitions. Coupled with higher realized prices for gas and a good midstream result, that drove profits up by 23% to GBP 1.15 billion. The mix is important here, as you know, given the very different economics between high price, high margin, but high taxed European production and lower price, lower margin, but also low tax for American production covering Canada and Trinidad. We split the stats accordingly, as you can see, as well as giving you the after-tax figures for the first time. In 2014, we will see lower oil production in Europe and DD&A rates will increase as new fields replace legacy low-cost older fields. That will squeeze margins in Europe. In contrast, Canadian volumes and profits will benefit from having a full year of the Suncor assets. That will not be sufficient to cover the lower European pre-tax profit, leaving total operating profit for Upstream gas this year at around GBP 1 billion. However, the lower tax rate does mean we can still target an after-tax result in line with 2013. In U.K. Power, overall profits fell by 45% to GBP 171 million. Nuclear output was once again very strong, and with the business also benefiting from higher wholesale prices, nuclear profit increased further. In contrast, trading conditions remained difficult for gas-fired generation, with continued very low spark spreads and the fleet no longer benefiting from free carbon allowances. As a result, our gas-fired fleet lost GBP 133 million, and we remain cautious on the prospects for recovery in 2014. Generation volumes from renewables increased as we brought Lincs onstream. However, unlike 2012, profits on slowing down wind farm interests did not contribute to the overall result, but they were offset by a write-down of our remaining development assets following the sale of the Race Bank project to DONG. On storage, operationally storage performed very well, with record withdrawals in the cold weather during the first quarter, followed by a record injection season over the summer. However, lower summer-winter spreads gave us a much lower SBU price, causing operating profit to fall by almost 30%. Storage spreads do remain very low, and the business is only likely to be around breakeven in 2014. The group did incur a number of exceptional charges in 2013. Low spark spreads in the Netherlands meant that we had to take a further provision for the tolling agreement on the Rijnmond CCGT. In E&P, we have some good reserve upsides in Norway, as Sam will set out, but also have some resource downgrades and some cost overruns on some of our projects in the U.K. Southern North Sea. Of course, for the accounts, we do not get to recognize the increased value in Norway but do have to take the downside impairment in the U.K. We also wrote down the carrying value of our existing Canadian portfolio, recognizing that the assets we bought from Suncor were considerably lower unit prices. In all, that gave us a post-tax impairment charge for the Upstream of over GBP 300 million. In storage, we announced in September that we would not be proceeding with the Baird and Caythorpe projects. That led to a post-tax impairment charge of GBP 224 million. Turning to cash flow, we generated GBP 3.8 billion of EBITDA in 2013. That was sufficient to cover interest and tax costs, a return of GBP 1.4 billion to shareholders through the dividend of the buyback, and to cover GBP 1.5 billion of organic CapEx. We also spent GBP 1 billion on acquisitions, increasing net debt, but also increasing the cash-generating capacity of the business. At GBP 1.5 billion, total organic CapEx was unchanged against 2012, but there was a shift from power to gas. Upstream CapEx increased with significant spend at York, Statfjord, Cygnus, and Valemon. In contrast, power CapEx fell, with the final spend on the Lincs wind farm being the only significant item. There were two large acquisitions in 2013. Hess's energy marketing business going into the DE business and the Canadian gas assets acquired from Suncor in partnership with Qatar Petroleum. In 2014, we expect CapEx to reduce. This reflects our decision to scale back E&P investment against a backdrop of rising costs in the U.K. North Sea without rising gas prices to offset this. While we continue to invest in selective projects such as Cygnus and Valemon, we will be increasingly selective about new investments and expect our E&P CapEx to average around GBP 900 million per annum over the next three years. With no major new projects in the pipeline, power CapEx is expected to remain low. On the M&A front, everything we have announced to date for this year has been on the disposal side, hence the inflow you see there, consisting mainly of the proceeds from the sale of the CCGT fleet. As you know, we are part of the preferred bidding consortium for Bord Gáis in Ireland, albeit the part of the business we are interested in would not involve M&A spend that would be material to Centrica. In summary then, flat earnings in 2013 with higher upstream profits helped by acquisitions, offset by margin pressure in downstream energy supply, particularly in B2B on both sides of the Atlantic, and by the loss of free carbon allowances. Looking to 2014, the pressures across the group. At this stage, we expect overall earnings per share to be below those in 2013, in line with recent analyst forecasts, once adjusted for the impact of the polar vortex and FX movements on Direct Energy. With that, I will hand you back to Sam. Thank you very much, Nick. In February last year, we set out our strategic priorities in the context of an increasingly international gas market. Just to recap, our priorities are to innovate, driving growth and service excellence, to integrate along the gas value chain linked to our core markets, and to increase our return through efficiency and capital discipline. Each priority remains equally valid today, reaffirmed by the developments we've seen in the current challenging market conditions. We delivered good operational performance in the year, as well as further improvements in our safety record. With the number of lost time incidents in 2013 falling by 45%, and no significant process safety incidents recorded during the year. I remain very grateful to my colleagues for all their commitment and hard work, particularly during the times when the company was the subject to much political and media scrutiny. We’ve also made strong strategic progress during the year. Across the group, we invested GBP 2.5 billion, both organically and through acquisition, strengthening our businesses for the long term. With over GBP 60 billion of long-term gas and power commitments in place, we play a vital role in securing energy for our customers. In North America, we've significantly enhanced the scale of our activities with the Hess Energy Marketing acquisition, transforming the size and capability of our B2B activities, while the Suncor transaction doubled the gas reserves in Canada and materially increased our 2C resources. In the U.K., we've simplified our residential energy offering, and we've made further improvements in the transparency of our reporting. We also realized value through the disposals of selected E&P assets, some of our U.K. wind assets, and our fleet of three CCGT power stations in Texas. However, with market conditions remaining challenging, we're taking positive action across the group. We have specific actions in place for each part of the business, improving customer service and developing innovative propositions for growth on both sides of the Atlantic, cost efficiency programs in British Gas, Direct Energy, E&P, and gas storage, and more selective investment upstream. I’ll return to this in more detail shortly. As the U.K.’s North Sea gas production continues to decline sharply, securing new sources of international gas is vital for Britain. In 2013, we signed two further long-term gas supply contracts totaling GBP 14 billion, including the agreement with Cheniere to purchase LNG from the Sabine Pass liquefaction plant, and an extension to our LNG supply contract with GDF Gas. Both agreements underline the crucial role that Centrica is playing in accessing global LNG markets and to secure supplies for the U.K., despite fierce demand from Asia and Latin America. Our acquisition of an interest in the Bowland Shale exploration license in the U.K. gives us a stake in a potentially important domestic source of gas for the future. We invested GBP 1.5 billion in organic CapEx across the group, the majority of which being in upstream gas, as Nick outlined. Here we achieved first gas from three projects in the past 12 months. In power generation, our Lincs offshore wind development is now fully operational, capable of providing enough power for some 200,000 U.K. homes. In North America, our $1 billion investment in gas assets from Suncor, in partnership with QPI, doubles our upstream scale in Canada. The assets fit well with our existing production and processing hubs in the region. The acquisition further strengthens our relationship with our Qatari partners. Initial production from the assets has been strong, ahead of our original expectations, and we now have over 1 million undeveloped acres, meaning significant potential for reserves and production upside, leaving us well-placed to benefit from any improvement in North American gas prices. Downstream in North America, the Hess Energy Marketing acquisition transforms our position in the B2B gas market, making us the largest gas supplier in the U.S. Northeast, and the second-largest supplier in power. With advantage positions along the gas value chain, the long-term customer relationships, this transaction really provides the differentiated business model, which is already delivering financial performance in excess of our investment case. This good strategic progress has come against a background of unprecedented political and media focus on the U.K. energy sector. The prospects for political intervention with proposals of a price freeze and a resetting of the market has created great uncertainty. On top of this, there have been calls for the breakup of vertically integrated suppliers, further damaging confidence at the very time when substantial investment is required for the country's long-term energy security. The U.K. now imports over half its gas requirements. With worldwide competition for energy resources, the U.K. must pay the going market rate. Financially strong companies are needed to secure long-term supplies for the country. The same is true of power generation, where although the government's Energy Act has now been passed, many important details remain to be resolved, and financially strong supply companies are needed to underpin investment in new low-carbon power generation capacity. There's been much debate about the efficacy of the retail gas market, and a competition assessment is underway in which we're participating fully. We should, however, not lose sight of the fact that the U.K. energy supply market continues to offer among the lowest cost prices in Europe, while energy efficiency measures are successfully reducing consumption. As a result, when adjusted for weather, average energy bills have in fact increased by less than inflation over the last five years. Indeed, average energy bills for our retail customers this year are expected to be around 8% lower this winter than they were for the corresponding winter last year. Nevertheless, public trust in energy suppliers has fallen to record low levels. While there's an improved understanding of the true cost of supplying energy to the home, the proposal of a price freeze would offer a false promise to customers when the large majority of costs are external to the business. We've engaged with policymakers to present proposals for more affordable ways to decarbonize and reduce energy consumption, helping more people at lower cost, without compromising the long-term decarbonization targets that we all support. We were the first supplier to reduce prices following the government's changes to the ECO program, passing on the savings in full to all our customers. We also recognize that improving transparency is key to rebuilding trust in the sector. We've simplified our product offering to four core tariffs. We were the first major energy supplier to introduce a tariff check for our customers and show clearly the margins we make in our upstream and downstream businesses, and indeed from different forms of power generation. Now, for the first time in our accounts, we're publishing our audited Ofgem segmental statement, and we encourage other suppliers to follow suit. Alongside trust, our continued focus on operational efficiency and service quality underpins our ability to earn a margin in energy supply, making these the core areas of focus. Through delivery of these objectives, we continue to see, through cycle, post-tax margins of 4%-5% as appropriate, given the risks and substantial commitments inherent in this business. In challenging market conditions, we're taking actions to position the group for the future. We've successfully completed our GBP 500 million cost reduction program launched 2 years ago. This has delivered operational and cost efficiencies for the benefit of both customers and investors, helping to offset the economic headwinds faced across the group. Downstream, under the leadership of Chris Weston, we've completed strategic reviews in both British Gas and Direct Energy, and new management structures are in place. We've also set new targets to deliver better service, lower costs, and where appropriate, drive customer account growth. Upstream, under the leadership of Mark Hanafin, as well as focusing on continued operational efficiency, we'll direct our capital towards the projects offering the most attractive returns and the lowest political risk, primarily in gas and oil, with limited near-term investment in power. In British Gas, we're targeting industry-leading service levels for our customers. This will be achieved through improvements to key processes, such as home move, switching to direct debit, and serving tenanted properties, where we can significantly improve the customer experience, reduce costs, and improve retention. These improvements will in part be enabled by our investment in a single residential CRM system for both energy and services. To date, over 80% of our residential customer base has now been migrated onto the new system. In BGB, the rollout of our new billing system is expected to deliver improved service at lower cost and should be fully operational towards the end of this year. We've commenced a cost reduction program in BGB to remove GBP 100 million of costs from the business by the end of 2015 from a combination of cost to serve and bad debt savings. As well as delivering operational efficiencies, we're also driving for growth. Although we experienced customer losses last year as a result of a brief period of high price differentials, we are much more competitive today and are targeting a return to account growth. We have an award-winning digital platform and a leadership position in smart metering and see the smart connected home as a core focus area, transforming the customer experience and enabling the development of attractive, differentiated products. We expect to have installed 1.3 million smart meters for residential customers by the end of this year, substantially more than any other supplier, helping customers to have real-time information about their energy usage. We have already seen a positive response from customers with smart meters, with lower consumption, none of the hassle of meter reads, no more estimated bills, and this in turn leads to improved customer retention. We have sold over 50,000 smart thermostats to date, with weekly sales doubling since the successful launch of our Hive proposition in September last year. We also continue to drive growth in both residential and B2B energy services through targeted segmentation of the customer base, expanded product choice, and leveraging of our insurance-based platform. In Direct Energy, market conditions remain challenging, with margin pressures expected to persist in both residential energy and electricity supply in B2B. Improving cost competitiveness is therefore a core priority, and we expect to deliver $100 million in cost savings from the underlying businesses over the coming year. We have reorganized this business under the leadership of Badar Khan, who is here today, and have introduced the role of Chief Operations Officer to help operational efficiencies on the enhanced scale of the business, alongside our core objectives of customer service and innovation. In Direct Energy Residential, we are already benefiting from the creation of an integrated operation center in Tulsa and a consolidated energy and services call center in Phoenix. We are also investing in a new residential energy billing platform for the Alberta market, with the potential to extend this to other parts of the business in the future. Building a range of innovative product offerings is core to our future growth potential in DE. Our Power2Go and Free Power Saturday products have both proved popular with residential energy customers. In services, the initial rollout of protection plans is delivering promising results, with over 80,000 products sold to date. Over time, we see significant potential for bundling of energy and services propositions, and we are already starting to sell services propositions through our Bounce online platform. In DE Business, the integration of the Hess Energy Marketing business is progressing very well, having transformed our capabilities in gas. Our priority is to retain key personnel and systems, continue to deliver good service, and high levels of customer retention. Looking forward, we see growth opportunities for Hess Energy Marketing to add supply positions from Marcellus shale producers and also helping customers switch from oil to gas. As Nick mentioned, the very cold weather of the polar vortex did impact the legacy part of the DEB power business through unusually high additional network and balancing charges in the first 2 months of the year. However, given the stress that this has placed on the industry, we could expect to see some repricing of risk during the year. Upstream, we have made good progress in developing our portfolio. Lower future wholesale gas and oil prices do present headwinds, particularly in the North Sea, given rising costs and reducing field sizes. However, we're successfully delivering value through reserve additions, particularly in Norway, underlining the quality of our previous acquisitions. The business is also well-placed to benefit from any upside in North American gas prices. Our 2C resources in Canada more than tripled in 2013, with the impact of the Suncor acquisition being supplemented by organic additions, providing us with the potential to accelerate our drilling program in Canada. We expect to double the wells drilled in the first quarter of 2014 compared with the fourth quarter of 2013. Given some of the challenges in the southern North Sea we faced last year, we strengthened our project management capability, and we have detailed project stage gates. We've reduced our rig commitments. We've also been increasingly selective in our investment spend, particularly against a backdrop of rising costs in the U.K. North Sea. Overall, we expect to reduce our investment to some GBP 900 million per annum on average over the next three years, around 20% lower than previously expected, and are targeting savings to hold our unit cash production cost flat over the next three years. We expect to direct the GBP 900 million of annual capital expenditure towards projects offering the most attractive returns with an increasing proportion in North America, alongside existing projects in the North Sea, such as Cygnus and Valemon. This change in mix will, over time, reduce our cycle time, lower our capital intensity and tax rates. Recognizing the increasingly international nature of gas markets, we will also continue to develop our LNG capabilities. As you can see on the chart, we expect the impact of this reduction in capital expenditure on near-term production to be limited, being in the range of 80-85 MMboe per year, or around 230,000 barrels a day of production. This will vary slightly as we continue to evaluate both acquisition and divestment opportunities to enhance the value of the portfolio. In summary, despite a difficult trading and political environment, we've made good progress across the group. Our strategic priorities remain robust and have actually been reaffirmed by recent developments. The Hess, Suncor, and Cheniere transactions each provide new platforms for growth. We have specific plans in place to drive increased operational efficiencies and capital discipline across the group. We're engaging with all political stakeholders in the U.K. to help inform the debate at a time when a stable investment climate is urgently required. Only solutions grounded on economic realities rather than political rhetoric are likely to deliver the investment needed to secure the country's future energy needs. We have a strong balance sheet providing flexibility for targeted investments where we see value. By executing against our strategy, we're building a solid platform for long-term growth, both upstream and downstream on both sides of the Atlantic. With that, I'd like to open it up to questions. Ladies and gentlemen, on the phone lines only, please press star 1 to ask a question. If we can start off the question, yes. Hi. Mark Freshney from Credit Suisse. Just 2 questions. Firstly, on the impact of the polar vortex in North America, the $70 million-$80 million lost profit. Previously, you have spoken about not having upstream generation assets and being prepared to run a risk of a 1 in 3 winter. Does the impact of the polar vortex change that thinking? Secondly, on the upstream gas and oil production business, given that you are reducing the CapEx spend over time, will you expect that to negatively impact your production levels, the 80 MMboe to 85 MMboe? Where would you expect the steady state to be in the long term at GBP 900 million spend per year? Thank you, Mark. Both very good questions. The impact of the polar vortex, the additional costs of the $70 million to $80 million, and I will let Chris fill in on this as well, have largely been balancing costs, network costs, effectively from the regulator as a bunch of peaking plant has had to be called out for production that was very seldom used. So this is not a 1 in 3 event, if you like. This is a 1 in 10, 1 in 20, maybe some people say a 1 in 100 event. To tie up capital for those peakers that would very seldom be used, actually, in our view, would not be an official use of capital. So it does not change our strategy. Chris, you might talk a little bit more about some of the ancillary charges, which have been at very unusual levels from the networks. I think there's still a debate ultimately as to where some of these network charges are shared. It was a very unusual event. Eight in the 10 highest demand days in the history of PJM were recorded in January 2014. It is a very unusual event. The charges that we incurred were from, as Sam said, ancillaries bringing in reserve generation, and there are four different categories of ancillaries that are brought in, and they increasingly get more expensive. Ancillaries last year in one of the categories, we incurred a cost in the whole year of just under $3 million. This year, we had that in one day on the 6th of January. It has been a different scale caused by this very unusual weather. Does it change our view towards assets? No. What we saw from the Hess model, they have positions across the value chain, and they weathered it very effectively. They did very well on gas. They had a tolling agreement with the Bayonne Power Station to supply New York, and that turned out to be very profitable. We think that we can mimic owning assets through a contractual position, and that we are comfortable with, and we will look for more tolling agreements in the Northeast and indeed in Texas. Now, there may be instances, in particular geographies, and if we continue to grow, that we would see some peaker assets, but we will be very selective about that. I think your second question, Mark, was around the reduction in our capital spend. Will it result in longer term reductions in production? I think the change in mix here is very important in that as we invest more in North America, which is lower capital intensity, we should be able to sustain production. I'll let Mark speak to that. Yeah. Mark, the model as you know, we're spending a relatively modest amount on exploration, GBP 100 million a year, and that as you go through a maturation cycle, is going to give you maybe 45, 50 million barrels of organic resources. We've always had the reserves supplemented by M&A activity. I think the key thing is we're at a point in the cycle where costs are rising, commodity prices are flat, and that's squeezing margins. The right thing to do is to cut back on CapEx. I think the good thing is that we can at least see three years forward at the 80, 85 million barrel level. Over that time, we'll take stock of where we go next. We'll be testing out the new acreage in Canada and seeing how our increased spend there is going. I think it's the right thing to do in the point in the cycle. There's plenty of time for us to think about where we want to be in terms of the mix of cash flow production returns. Martin. Thanks. Yeah, Martin Brough from Deutsche Bank. Just a couple of questions. If commodity prices stay at current levels in the forward curve, do you expect BGR's commodity costs to be higher or lower this year than last year? The second question is, do you still think the international functional organization downstream is appropriate? The drivers facing Direct Energy and British Gas are very different, and National Grid found when they were under increased regulatory scrutiny, it was helpful to have separate local businesses to allow you to engage with local regulators and politicians rather than having shared costs across the Atlantic. I think in terms of BGR commodity costs, obviously, we have bought a certain amount of the commodity for this year. But equally, some of it is open, and it will depend where the market goes. Chris, do you want to comment on that at all? I should add the commodity itself will be lower because volumes will be lower based on the current expectation. But in terms of price Sam's comment, absolutely right. Yeah. I think your second question, which is around the appropriateness of the structure that we have in place. I think we've only just put the structure in place. It is delivering real benefits. Some of what we talked about, what Mark has been talking about in terms of the upstream, in terms of being sure that we have the best capital allocation through a single filter, leveraging the subsurface, the project management skills, the engineering skills on both sides of the Atlantic, I think is bearing fruit, improving the efficiency of our Canadian operations, and bringing some cost reduction techniques to our North Sea operations. If you look at the downstream, again, we've got, I think, great opportunities to share, whether it is billing systems, whether it's services, technologies. Some of the things you've seen with Hive and the remote heating control appliances, but also a lot of the work around smart meter technology and also commodity risk management and some of the systems and processes we have in place, I think, can really be shared across both businesses. What we are not doing is moving to a total global function where, if you like, we have a single marketing function for the group worldwide, and we have a single sales function or we have a single back office for the group worldwide. We still do respect, and as I mentioned, Badar Khan is here. He runs the North American business, so the downstream business there is still run as a separate business and has visibility right to the executive committee on a regular basis. So I think that's very important. Ed. The first one is on the dividends. I was just interested in your decision to maintain real dividend growth in 2014, given that EPS is falling. Are there any constraints on that? Is there a payout ratio which you'd be unwilling to go beyond? The second question is around decisions to keep CCGTs running. I think I've asked this before, but given the substantial loss that you've made in CCGT since 2013, given your expectations that spark spreads weren't to improve any time soon, why are you continuing to run them? The third question for Nick, because he's leaving, so it might be his last. But it's around the cash flow implications of the decision to refund customers that are in credit. So let me ask Nick to take the first one around dividends. I'll ask Mark to speak to the second one around CCGTs, and Nick can take the last one on cash flow, and then you, if you would like to add to it. So, our policy remains to increase the dividend in real terms. Clearly, our debt ratio is only 64%. We have good cash generation, balance sheet's in good position. So we can weather short-term variations in earnings and still maintain that commitment. Clearly, eventually, you have to have earnings growth to cover dividend growth. But given the financial position the group's in, we can go for quite a long time and still continue to increase the dividend even if we don't have earnings growth in 2014. Your second question, I think, was around continuing to operate the power stations on a cash flow basis. It's not as bleak as it is on an earnings basis. Why keep hitting your head on a brick wall, I think is the question, Ed. I think the answer, on a cash basis, it's not as bad. It's still pretty bad. It's kind of break even. And obviously, heavily loss-making on a P&L basis. I think to answer the question properly, you've got to step back and say, so what do we think is going to happen in the future? And if you look at forward spark spreads, we're currently at zero to negative. That continues for a year or two. And even in 2017, when many people are talking about the lights going out, we see spark spreads of barely a couple of pounds per megawatt hour. I think our fundamental view is slightly stronger than that, but there are good reasons why the spark spreads still remain persistently low. That is that if you look in 2017, peak reserve margins are falling perhaps below 5%, approaching zero. But base load reserve margins are close to 50%. So you've got a different shape in the market. The lights aren't going to go out consistently, but they're going to start to flicker if renewables are not working properly in winter. That's the challenge. The market isn't giving signals that drive investment decisions in CCGTs. So something has to change in that, and that, we believe, is a capacity market. If a capacity market comes in, it needs to apply to existing assets, and we'll be bidding into that. I think that's the long answer, but the short answer is on a cash flow basis, broadly break even with some potential when the right market mechanism is in place. Just to be absolute clarity on the CCGTs. The owned fleet is roughly break even on a cash basis. We do have the Spalding lease, which does take us into losses and some fixed overhead costs, which does push it a bit further down on a cash basis. But overall, the owned fleet, the six owned ones are breaking even cash. Your other question, Ed, on the cash flow implications of refunding customers. We already do this. This is not a significant change for us. Anyone who's GBP 100 in credit at the end of their plan year, we already refund it. Not many people are, so it will have a bigger impact for others than it will have for us. We will ask customers whether they want in reducing that GBP 100 to a lower threshold, we'll ask them whether they want that. Surprisingly, not that many do, actually. They prefer just to build it into their plan for the following year. So I very much doubt you'll see any significant impact on the overall group financials from it. I just add another point around that is that we have an online proposition that enables people to adjust their own direct debits. Some 2.8 million people have actually been on and looked at their online, their direct debit estimates and their direct debit payments. Over 60% of them have been very happy with the level. Some have actually increased their direct debit. About 20% have increased their direct debit because they are worried that they are going to end up getting behind, and about another 20% have actually reduced their direct debit because they think they have been going ahead. So actually, there is not going to be a great cash flow impact from this. Okay. Thank you. Hi, I am Jonathan Quarry. A couple questions, please. Firstly, on your GBP 1 billion write-down, I understand that you put that through your numbers in this year. What would your underlying EPS have been without the write-down on the depreciation charge? Secondly, following up from Ed's question, if spark spreads do not recover, what capacity payment do you think you are going to have to bid in for to, A, keep yours open and, B, potentially build new ones? Finally, just to throw one in, on water, obviously, they are introducing water competition at retail, in the non-households, definitely. Are you looking at entering that market? If water exit is approved in the water bill, would acquiring water customers be something you would be interested in? Okay. Nick took the impact of the write-downs, and then Mark, perhaps you talk about what price would be necessary to incentivize new generation in a capacity market, and I will talk about the water. The write-down, obviously, we took toward the end of 2013, so it had no effect in 2013. But even looking forward, a chunk of it, of course, was on new storage projects, which we weren't depreciating anyway. And the upstream ones, the reason we've taken the write-down is because the reserves aren't there and the economics of getting the gas out from those fields. So the depreciation per unit of production coming out of those fields will be broadly what we would have thought of before. It won't actually impact it. That's why we've had to do the write-down, because it was getting too high. On capacity payments. On capacity payments, they're going to be in the current design, they're going to be three tranches of that. Existing assets get a one-year capacity payment, refurbished assets, three years, and new assets, 10 years. And I think obviously it's a competitive process, so I'm not going to explain to you what our strategy or our pricing might be. But in round numbers, you probably need GBP 65 a kilowatt to be bidding in new capacity for either CCGT or open cycle. We have a range of possibilities for that if the market works properly, and our existing assets will obviously look to hopefully cover some of the losses between when the auction happens and 2018 when this comes in. Otherwise, we get back to Ed's point, which is why not close them? On your final question around should we be looking at diversifying into water supply if the market opens up to retail competition, I think we've said very clearly this is an energy and energy services business. Historically, Centrica has had attempts at diversifying into other businesses and they haven't been particularly successful either because of data protection issues or because of systems issues or actually because the customer is looking for something different. So that's not an area that we'll be pursuing. John Musk from RBC. Two questions from me as well. Firstly, on the customer account target and returning to growth there, obviously with a slow start, let's say, to the year, how confident are you in getting that and what is the mix between services and energy customers within that? Secondly, on the carbon floor or carbon tax in the U.K., is there any insight you can give us on what you think may happen there? Importantly, what would you like to happen there? Okay. Let me ask Chris to touch on the first one around customer account growth, both energy and services, and Mark to speak to the carbon floor, which is I think a political judgment as much as an economic one. As we've said, we've continued to see customer losses in the front half of the beginning of this year, about 100,000 customers. But we have seen that massively slow down. That was a hangover from the price rise in October, and it was helped by our price reduction on the 1st of January. We have also seen sales increase of energy, and we are just about getting to break even now. We are looking at our propositions, and seeing how we can make them more competitive. The current movements in the curve help that, and I am confident we will get back to growth in the energy customer base. Whether we will make up that 100,000 that we've lost at the beginning this year, it's too early to say. In terms of services customer numbers, the customer base in services has been declining for the last three years or so. There is an awful lot of focus on getting growth back into the services customer base. I'm confident we will get to growth this year. One of the key things we have to do is to get the energy call centers back to where they need to be, and they are pretty much there now. They are handling calls efficiently with short ASAs. That provides bandwidth for the call centers to be able to start to lead generate for services. I see that as a key channel for the services business. Services business is also extremely effective online. We find about 25% of our sales for home care come through online. Indeed, that is our biggest channel. I think there is a lot more that we can do there because we have a very good presence online. In both of them, both energy and services, I am looking to get back to growth this year. The carbon floor. In terms of carbon, the question, what's happening? What do we think about it? When HMT brought this in, obviously the scheme was meant to provide a floor trajectory out to 2020, leading up to GBP 30 per ton of carbon. It was based on a difference between that floor and what the EU allowance was on the ETS price. I think HMT, what they do, they forecast it 2 years in advance. They thought the EU price was going to be higher, which meant that this tax year, 2013-2014, the tax element of it is only around GBP 5. It's doubling next year. Again, they've underestimated the EU allowance price, sort of GBP 9.50. Now we have the prices for 2015-2016, which are doubling again to GBP 18. That's the tax element of it. Now, when you look at GBP 35 per ton of tax on carbon, that's GBP 2 a megawatt hour on the power price. At GBP 18, you're looking at GBP 7 on the power price. I think that's where the issue is coming in. Number one, HMT is probably surprised that the EU prices haven't come up and the tax is larger. Secondly, large industrial users are concerned about that GBP 7 disadvantage versus Europe. From our point of view, we understand the affordability issue and obviously have some concerns about that as well. At the same time, it was the only mechanism that was actually beginning to send a market signal that says carbon has a proper price for emissions. The ETS is hopeless for that. The commission has not managed to figure that out. HMT did put that in place. It gave a clear signal, and it does drive switching. It hammers the clean dark spread, for example. It's a very difficult one. I think the options are either a freeze at the 2015 to 2016 level or a lower trajectory from 2015-2016 onwards. I think that's where it's going to end up, and we understand that, but we still think it's an important part of the energy mix and the correct signal. I think it has done a lot to encourage the coal to gas switching in that sense. If you look at it in terms of overall cost of carbon abatement, it's still relatively efficient compared to a lot of other mechanisms. You shouldn't also forget that if you reduce the carbon price, then actually the cost of feed-in tariffs and ROCs is inevitably going to go up. Ian Turner from Exane. Can I ask you what you can do to mitigate the risk of Labor's proposed energy price freeze, either before the election or after the election? Because no one's asked that question yet. Yeah. It's a very good question. Obviously, in a competitive market, there are things we can talk about and things we can't. But the obvious things are working both in terms of the customer propositions we have. We already have over 20% of our customers on fixed price. That's clearly one lever that we could potentially pull. There's another lever in terms of can we procure some of our gas on something that is closer to a fixed price basis? Those are some of the big drivers. Obviously, as we get closer to the-- We're still 16 months away from an election, as we get closer to the day when we assess what the probabilities of this are, which is obviously a political judgment, not only on which party, but whether it's going to be a coalition government. I think there are a wide range of views, and if there is a majority labor government or a minority labor government seeking to govern, what are the chances of this being enacted? Those are the judgments that we'll have to make. But we are very focused on a strategy for it. Andrew Miller, Goldman Sachs. Just two questions on politics. One, can you say what the main issues would be for Centrica if Scotland voted for independence, aside from the currency and maybe other things? My second question was, have your partners, such as the Qataris, expressed any views on the political issues in the U.K., and have they expressed that to either of the two parties? The first question I think is around the implications for us of Scotland voting for independence. We've sort of said publicly, and we've stated that actually at the end of the day, this is a matter for the Scottish people. But it will be complicated in the energy sector because obviously there is the natural division of spoils, but also division of liabilities in the North Sea, because a lot of fields are now getting to the end of their field life and dismantlement issues, which are being picked up under the new dismantlement agreements with the government. A large share of that is being picked up by the government. So obviously, there's a liability there that comes for the fields that are deemed to be in Scottish waters as well as the production revenues. On renewables, clearly we're in a situation where a lot of the U.K. renewables, onshore wind in particular, is located in Scotland, and England will be paying the feed-in tariffs to Scotland. So how durable those are, we don't have significant investments in onshore wind and renewables, so that's not an issue for us, but it will be an issue for the energy industry. The third piece, of course, is that we've got, together with EDF, two nuclear power stations in Scotland, which again, will ultimately have to be decommissioned and who has the liabilities of those? So these, I think, are going to be complicated issues that have to be worked through. Remind me of your second question, Andrew, was around It is more on- The Qataris. Yeah. And the political situation in the U.K. A number of international investors and some of our international gas suppliers, without getting into specifics, are concerned about what is going on in the U.K., because actually the U.K. had up until recently, as you know, been a bit of a beacon of stability and political consensus and a good place to invest. I think we saw that obviously with the share prices of some other European countries. When I talk to both European counterparts, but also some of our gas suppliers, they are increasingly concerned about this. I think that is a great pity because as we all know, reputations are easily lost and take a long time to rebuild, particularly in the investor community. Hi, it is Harry Wybyrd from Barclays. Two questions. Firstly, you mentioned that 4%-5% post-tax margins are appropriate through cycles. Can you confirm whether that is what you are assuming for your 2014 guidance? Following on from that, is that consistent with your strategy to increase your account numbers, particularly in BGR? Obviously, there are costs involved in acquiring customers. Secondly, on Hive, you mentioned you had sold 50,000 smart thermostats. I was not quite sure, were those all Hives or was it a subset of those Hives? Again, following up from that, have you seen any changes in energy consumption in your customers who have Hives? The 4%-5% margin is something that there is no entitlement here. We actually have to work hard in a competitive market to continue to take costs out. We will, and have historically had, with the scale we have and the cost reduction programs and the productivity and the online offering, had higher margins, if you like, than the industry average, but we are going to have to work hard to do that. In terms of specific guidance for 2014, as always, much will depend on the weather and the wholesale price, as we always say. But we think that fundamentally, that 4.5%-5% post-tax is a good number. The propositions that we are coming out with will help us grow our customer base, but we have to keep taking costs out of the business to be competitive. In terms of the Hive product- So- Yeah. In Hive, actually to date, we're a little bit more than the number there. It's getting on towards 60,000 now. We are seeing it being very popular. There is a small proportion, I would have to check the number, but probably about 19,000, 20,000 that were the original remote heating control that we evolved into Hive in that number. What are we seeing? It's very early days and how it's affecting people's energy usage, I don't know if it's surprising or not, about 45% of the interaction that we see between the customer Hive and their heating happens when they're in their own home, in their sitting room, probably turning up the heating while they're watching telly. We are getting some interesting insight. It's proving to be very popular. People are using it pretty much every day, so a high incidence of use. The initial indication on energy usage is saying that about 30% of the customers are using roughly 10% less energy or less heating. That is very early. I wouldn't take too much from that data, but those are the initial indications that we are seeing. It's proving to be a very popular product. Thank you. Akis Athanasiou with Agency Partners. I have two questions and one follow-up from a previous question. Firstly, you talked about 770 million barrels of oil of 2C reserves. Could you give us a rough idea of where the geography of that is? Also some color on the location of where you think you will be spending the broad split of that GBP 900 million per annum, particularly North America, U.K., Norway. Second question is on your strategy on gas E&P in North America, is it coincidence that where you are now is roughly matching what your LNG export capabilities are and that any further acquisitions will be matched by that, and therefore it's almost completely dissociated from your downstream activities in North America? Would that be a good way of looking at things? My follow-on, I was a bit confused with Nick's response on the asset write-down. As far as I can make out, the asset write-downs on the fields, Seven Seas, Ensign and Rhyl, seem to be almost the entire development costs of those fields. There is very much there to depreciate. I cannot see how, unless I am missing something, you are actually preserving unit depreciation rates. Let me ask Mark to take the first one, which was around our 2C resource base. Where is it, and roughly what is the split, if you like, of our CapEx? I think really your question, Mark, is between the North Sea and North America. In terms of 2C, which I think was your question, about 250 of that is Europe. Okay. 250 in the balance is the Americas. In terms of CapEx spend of that 950, you have 100 of maintenance, round numbers, 100 of exploration. You have 750 in round numbers of development. Two-thirds of that 750 is non-op. The big ones, Cygnus, Statfjord, Valemon. 250 of it is operated under our control. I would say, again, these are rough numbers, half and half in terms of North Sea and Canada. Of the 900, about 150 is Canada in CapEx. I think in terms of the strategy for acquisitions, it is coincidence that the volumes that we have coming out of Canada, if you like, are roughly equal to the volumes that we will need to export from the Cheniere facility when it comes on stream. We have also got a big and growing gas business as retailers, both in the domestic space, but now increasingly with Hess Energy Marketing in the B2B space. So in order to provide the structural hedge for that, reduce our collateral, if we can find the right opportunities, whether it is through continuing to develop our Canadian position, either developing some of the 2C you just heard about or whether it is looking at infill acquisitions or also looking at U.S. shale opportunities. If we could find the right opportunities of value, and we have been looking, as you know, for a number of years and found that either the resources are dry gas and very low return, such as a lot of the Marcellus' low gas prices or they are liquids-rich but very short reserve life where you get on a treadmill and have very high capital intensity, and you have to keep putting the money back in. We haven't found yet an opportunity that, if you like, fits what we would like to do, but we still continue to look for upstream gas opportunities in North America because we need to go beyond just providing enough gas for our export. We also need to supply our North American customer base as well. On your question about the unit depreciation, I mean, you are right. We have written off a very large part of the original development costs. We have had cost overruns, of course, so we have had to put more cost into it. We also had to downgrade the production expectations, and that is why you end up with a unit depreciation rate that is not dissimilar. Is all that write-off in PPE or physicals square as well? Which write-off. Is it in those PPE assets. Yeah. Peter. Peter Harrison from Liberum. Given the challenges in finding good things to put your capital to work in and given your share price, what discussions has the board had about increasing the share buyback beyond just using disposal income. Well, I think we obviously have just completed one share buyback. We have announced as a result of the asset sales, the GBP 420 million share stock repurchase, which we haven't yet started. I think we shouldn't get ahead of ourselves here, but clearly, we absolutely understand the point that with our share price where it is, when we match it up against acquisition opportunities, that the acquisition opportunities have a higher hurdle to cross in terms of looking at the alternatives. Nick. Evan Rees from J.P. Morgan again. Three questions. First one is in terms of customer losses. What proportion of your customer losses were to smaller suppliers? Do you think it's a level playing field? I guess now this is my third question. But in terms of gas margins in the segmental statement you put at the end of this, it seems that gas margins, again, are significantly higher than electricity margins in U.K. residential supply. We've obviously seen a lot of political focus on that. Why do you think that is? Do you think it's meaningful? Let me ask Chris to answer both of those. Small suppliers are taking a larger proportion of our losses. At the moment, we're seeing about 40% of our losses go to smaller suppliers. They have an advantage from not having to bear the ECO or the environmental costs in full, which is worth about GBP 50 or so. But increasingly, as they move above 250,000 customers, and some of them above 500,000 customers, that will disappear. Some of the ones that have reached that threshold, you see their prices are very similar to ours now. In terms of the margin, we look at the market as a dual-fuel market. 84% of gas customers in the U.K. take dual fuel from a single supplier. We would look at the dual fuel margin at 4.5% after tax as being reasonable. It's a competitive market, 19 competitors out there. They all price differently. They all have different pricing strategies, and that is the benefit of a competitive market. We will look at that as we go forward and work out what is going to work best for us to attract and retain customers, but we're happy with where it is at the moment. The only point I would add to that last point is that the data that they selected was actually based on an extremely cold winter when we obviously had very high gas margins. If you look at today's data that we published, after tax we are down to 6.5%, the electricity margin is actually less than 1%. So at the end of the day, if this does converge, then our electricity margins would have to move up. It is Ashley Thomas from Société Générale. The GBP 1.3 billion of pre-productive capital in the E&P business, I assume going forward with the lower CapEx and with Cygnus coming on stream, over the next 3 years, I would have thought that trend should be down. There will be less pre-productive capital in the business. Could you just give us a feel of the scale of how much could potentially come on? Also, could you express your confidence in whether those committed projects will hit their targeted hurdle returns? Yeah. I will let Mark answer the detail, but I think your general proposition, and you see into the 2013 numbers compared to the 2012 numbers, an improving ROCE picture. Obviously, we have the commodity price not going in our favor, but nevertheless, the pre-productive capital we are working our way through, it is principally Cygnus and Valemon as the 2 big projects, if you like. Plus the Statfjord upgrade, which has very high returns anyway, but I will let Mark speak to the specifics. Yeah. I think that on the general point it is correct that as we reduce CapEx, and some of the longer-dated projects, particularly ones that have come as part of an acquisition where you have got capital essentially from the acquisition allocated to that and then spend, that comes off. So it reduces it. I do not have the numbers at my fingertips on that one, but the general point is true. I think on projects that we are doing, and we are being very selective about, we look at some of those impairments in the Southern North Sea and we say, yeah, there is the usual mix of excuses that people like to use about host platforms and third parties not doing what they should and a failed well that statistically can happen and difficult drilling conditions and all those things. But basically, we also needed to do quite a few things better than we did. That comes down, when you peel the onion back to the root cause, the really root cause, it is being driven by risk schedules. It is being driven by a dash to get to first gas. All those things are fine, but not if it means that you move forward before you have done all the subsurface work, the facilities engineering, the well planning and so on. So we have put in place an assurance process around stage gates very rigorously that things do not move forward until they are ready. That is for our projects. I take no heart from the fact that the industry is awful at this, and if you benchmark it, pretty much every capital project looks like that. I do not think it needs to be like that, and it cannot be like that when you have got flat commodity prices because they do not bail you out anymore. So I am very focused on making sure that our projects go right. We then have to be a good non-operator as well. A lot of our capital is going into non-operating, and we are taking that very seriously. We are not a financial investor in these things. So for example, Cygnus. It is a huge project. It is shallow water. It produces all kinds of challenges for lifting and so on. But we have people embedded in that project. I think GDF are a good operator, and we will work very closely with them to try and make sure that that comes in good shape and delivers a return. Can I just add to that? I think you are right to point out at Cygnus, you will not actually see pre-productive capital come down until Cygnus comes on stream. So over the next year or two, it probably just creeps up a bit and then will come down sharply when Cygnus comes on, and to a lesser extent, Valemon, that Sam referred to. Yeah. Could I just check that the mid-20s RCF metric is still valid given what looks a more challenging environment for the business? You are talking about credit ratio? The debt metric. Yeah. Yeah, look, I think you have seen some of the commentary that the rating agencies have put out. It is fair to say that they have seen some changes in the sector and expressed concerns about it. S&P have been quite reasonably specific about it and changed some of the thresholds that they are looking for. We are still above the thresholds that they talk about, a different metric. Moody's are less precise. They still talk about the mid-20s. But clearly, that in itself is a range. They are probably a little more cautious than they were six, 12 months ago. It is McClaren from Bells. Good morning. May I just ask about your view of U.S. retail margins and the extent to which that has changed your appetite for further M&A? Also, just wondering about the extent to which you have now exhausted efficiencies in the BG Home Services business. If you now really need that revenue growth in order to see higher profits. We ask Chris to deal with both of those. First one being around U.S. retail margins. Has that changed our view of retail for acquisition purposes? The margin squeeze we have seen has largely been in the B2B market. I think what we have seen in the polar vortex has been a large impact, and it will make people think about the risk that they price into their margins. We have seen margin squeeze over the last 12-18 months, and it got to its worst at the end of last year. We have been through a crisis much like we did in 2007, 2008, where we did see competitors reprice risk. The initial indications that we are seeing in terms of pricing in the way the auctions are running at the moment suggests that people are being more sensible now about margins. Does that change our view on M&A? We will look at each one in its own right and work out whether it is a sustainable business model, how it fits with our existing business, geographically where it is. I think at the moment in the Northeast, we are less inclined to go forward with M&A. Maybe in Texas it is still attractive. It will depend slightly geographically. Going on to the second one, in terms of costs in BGS, there has been an intense focus on cost in that business. I would not say it is exhausted. I think we can continue to do more on efficiency. But I think more importantly now, we have to look at how we create resilience in that service model that we offer to our customers. We are looking at being able to operate in a one in 10 winter level, and that is what we are building the business to be able to do. It might mean some changes to the way we deploy engineers to better meet customer needs at certain times of days, but we will do it with an eye on efficiency. We do have things like the new systems coming in, which are shared with residential energy, which will help in terms of that. But the key focus beyond the service levels is then getting back to growth and using the insurance product set capability that we have and our ability to price, and price more effectively for individual customers and risk is where we will see that come. Any further questions? Okay. Time for one more. Hi. Peter again from. Nice easy one to finish with. Your struggles to generate growth is bound to at some point create a breakup story or breakup speculation. I can give you the opportunity perhaps to give us your top three reasons why Centrica is adding value to this mix of businesses and why that is better than perhaps being broken up into three or four separate entities. Sure. There are different dimensions. People talk about different things when they talk about breakup. But if you look at the group as a whole, why it's worth more than the sum of the parts. I think firstly, as the benefit of integration, as we've seen in terms of reducing our cost of capital because it actually enables us to deal with the volatility in the markets and shelter some of our customers from that volatility. I think those benefits are very clear. It also gives us the credit support that we need to be able to enter into long-term gas supply agreements. It's no surprise to you that when Centrica was first created at demerger, it had to be created with Morecambe Bay because everybody recognized that as a pure retail-only enterprise at the scale we are, we wouldn't have been financially viable if we had sudden commodity price shocks. There is a real benefit to integration to our shareholders through a lower cost of capital, but also to our customer. Then I think the second piece behind your question is, if you like, the benefit of North America to the rest of the group. And actually what we're seeing is not only do we believe that as the largest energy, liberalized energy market in the world, it has huge growth potential, but we can also leverage some of the skills, some of the services, things that we've been talking about, Hive and smart metering technology into North America. There's a huge opportunity for energy efficiency there. The size and scale that we are, just to paint ourselves into a corner in the U.K., I think would be inappropriate and constrain our growth. Also the U.K. is becoming increasingly import-dependent on its gas. Therefore, a lot of the gas that we are going to be supplying in the U.K. to our customers is going to have to come from international sources, the U.S. being a very important part of that. When we look at the whole, the totality of this, there's no question in our minds that not only is the whole worth more than the sum of the parts, but actually if you were to break it up, we wouldn't be able to enter into the sort of agreements we talked about with the Qataris, with the Norwegians, to also enter into the LNG agreement in the U.S. and to take on some of these very big commitments and continue to invest at the level we do to keep power stations running, but also to keep the gas flowing. That's the simple story. I think that's probably a very good note to end on. Thank you all very much for your continued interest and all your time and very good questions. This concludes the Centrica 2013 preliminary results call. If you would like to hear any part of this conference again, a recording will be made available shortly. Thank you for joining. You may now disconnect your lines.