National Grid plc (NYSE:NGG)
August 04, 2011 9:30 am ET
Paul Whittaker - Director and Director of Regulation UK
Nick Winser - Chairman and Chairman of Transmission Executive Committee
John Dawson -
Bobby Chada - Morgan Stanley
Jamie Tunnicliffe - Redburn Partners LLP
Peter Atherton - Citigroup Inc
Mark Freshney - Crédit Suisse AG
Edmund Reid - JP Morgan Chase & Co
Good day, and welcome to the National Grid UK Regulation Update Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to your host today, Mr. John Dawson, Director of Investor Relations. Please go ahead, sir.
Thank you very much. Hello, everyone, and welcome to National Grid's conference call on our U.K. regulatory developments. My name is John Dawson, Director of Investor Relations for National Grid, and with me today are Nick Winser, Executive Director responsible for our U.K. businesses, and Paul Whittaker, U.K. Director of Regulation. The call should last about an hour, and we intend to spend the first 30 minutes sharing our perspective on the key issues arising from the business plan submission we made on Friday of last week. I would draw your attention to our cautionary statement, a copy of which you can find contained in the presentation.
Before we get into the main part of the call, let me update you on 2 other developments in recent weeks. We're not presenting today any detailed materials of Ofgem's initial proposals for the one-year rollover of the transmission review that we'll publish in Tuesday. As you would have seen, this proposed a 6% RIIO increase in revenues in our Electricity business next year and a 12% increase in our gas business. If you have any questions about this, you are welcome to ask them at the end of this call or to contact the IR team directly.
Moving briefly to the U.S. for a moment. You would have seen that we filed for the recovery of a number of deferrals in our Niagara Mohawk electric business. This is the expected filing we agreed to make as a result of our recent NiMo rate case, covering both deferred expenses and capital expenditure. As we have said previously, this totals around $236 million and, if approved, would come into effect on the 1st of January 2012.
Turning to the submission of our business plans. Headlines include a combined Totex of GBP 30.7 billion on a nominal basis, split GBP 25.4 billion in CapEx and GBP 5.3 billion in OpEx and split GBP 22 billion in electricity and GBP 9 billion in gas. Nick Winser will share with you a little more detail around this investment, why it is required and what we will be delivering. The plans also include our proposals on financing for the notional regulated entities, in other words, NGET and NGGT. These include a cost of equity of 7.5% and 55% gearing. In addition, we have proposed the 2-period transition to 45-years asset lives for a new electricity investment. Paul Whittaker will take you through this in more detail.
Finally, as part of the funding of the notional entities and the move to a new capital structure, the plans include GBP 4.1 billion of notional equity injections into the individual notional businesses. I will conclude the presentation by providing a group context and drawing a clear distinction between the financing of these individual notional businesses and that of the group as a whole. We'll then turn the call over to questions.
Let me know hand you over to Nick, who will take you through the highlights of our submissions today.
Thank you, John, and good afternoon, everybody. As you know, this is the first time that we finished through the RIIO process. And what we have submitted is a fully thought-through package. Our proposal needs to balance 4 important drivers: first, maintaining safety, security of supply and reliability; second, delivery of legislative climate change targets; thirdly, of course, affordability of customers; and fourthly, all of this needs to be underpinned by the need to deliver reasonable returns to our investors.
We have carefully considered how best to balance between these 4 drivers. This thinking has informed our planning of what we will deliver, how we would deliver it, what is required to finance this and how it will affect key stakeholders. A key part of our decision-making process has been the extensive program of stakeholder consultation, and I'd like to take the opportunity to thank all of our stakeholders for their really excellent inputs. Therefore, these plans have not been developed in isolation. This is not simply National Grid proposing what is needed for the next decade in putting together our submission, [indiscernible] extensive feedback about possible changes to the business plan, and Paul will talk about this later. In particular, we have included a number of important flexibility mechanisms to enable the price control to adjust for different outcomes. Before I take you through the highlights of the plan, I think it's worth reminding you of the context in which we are submitting these plans for the next decade of U.K. transmission development.
We are already a considerable way into an exciting and challenging time for the U.K. transmission businesses. Changing sources of gas supply, ageing electricity generation fleets and ambitious carbon reduction and other environmental targets are all driving changes to our systems. At the same time, many of the existing assets on our transmission systems are reaching the end of their useful lives. We are in a decade of transmission developments, which will be absolutely essential to pave the way towards a low carbon economy. In order to aid our planning process, National Grid has developed a number of scenarios for the future energy supply mix taking account to the drivers I've just mentioned.
Our Gone Green scenario is a view on how the energy might develop in order to make a legally binding carbon target for 2020 and beyond. It has gained general acceptance as a credible base case amongst our key stakeholders. This has determined the spend in our baseline plan. The scenario only assumes a marginal increase in the level of demand for electricity over the next decade but, of course, significant growth thereafter. And that's allied to the big changes in the generation of electricity during the planned periods in particular to drive down the carbon intensity of that generation.
On electricity supply, we anticipate a big growth in wind generation, more interconnection and some growth in gas generation plant, while nuclear remains a relatively steady proportion until the end of the decade. Most significantly, we see a drop in coal and oil generation that helps towards the 2020 government environmental targets.
On gas, demand also remains relatively stable, but further investment is acquired on that network to connect new gas for our generation plants and to accommodate new storage capacity and imports as domestic supplies reduce to around 25% of the total demand by 2020. We recognize that this is one scenario amongst many, and we have stress tested our plan against a number of other scenarios, in particular, around slower or accelerated investment in wind and nuclear generation.
So turning now to some of the details of our baseline plan. To make new comments of the ideas from 2013 to 2021, our plan is to deliver the following in our electricity transmission business and gas: around 350 route kilometers of new transmission line; around 1,500 route kilometers of replacement lines, including Phases 1 and 2 of our London tunnels projects; over 250 kilometers of underground cable; nearly 50 new substations; and 2 new HVDC interconnectors to Scotland jointly owned with the Scottish tiers.
In our gas transmission business, NGGT, we expect to deliver 24 new compressors and around 1,000 kilometers of new pipeline. Overall, compared to our investments over the last 10 years, this is a significant increase in activity. In order to achieve this, we estimate that we will need to recruit and train around 1,200 new engineers, project managers and skill technicians in electricity and nearly 400 in gas. We've estimated the total cost, operating cost and capital cost of delivering these outputs to approximately GBP 31 billion over the 8-year price control period. That's for both gas and electricity. This forecast includes challenging assumptions around underlying efficiency improvements on both capital spend and operating costs.
Looking in more detail over the electricity transmission business under the baseline plan. During the period, we are predicting that we will connect 24 gigawatts of new generation and 2 gigawatts of additional interconnector capacity to our system and begin connection works for further 24 gigawatts, in particular, new offshore wind farms and nuclear plant.
The profile spend we are proposing is broadly consistent with our previous plans, a steady increase to 2015/16, driven by an increase in load-related CapEx and on a sustained level of investments until it tails off again to the decade. This reflects the very large reinforcement projects that we've identified as being required to enable the connection of future low carbon generation.
You will also notice a step-up in the level of non-load-related CapEx from 2017. In effect, we are using this workload as a balancing act over the periods to if you like smooth the CapEx profile to the extent load-related expenditures moves backwards in time. We have the opportunity to bring forward some of this non-load CapEx. In using the non-load investment as part of the plan, we do, of course, need to consider carefully how we will manage network risk across the period, and we've done that.
In delivering the outputs we've discussed, we predict that we will need to spend GBP 18.2 billion of CapEx and GBP 3.7 billion of OpEx over the 8-year period. Please note that these forecast outturn numbers include an assumption of future inflation of around 3% per annum. All the numbers we have submitted to Ofgem are in 2009/10 RIIO prices as specifically applied by Ofgem. They are fully consistent with the outturn numbers we are presenting here.
Turning to our gas transmission business. We expect investments in this business to be lower than that in electricity transmission but broadly proportional to the size of our existing business and with a much more volatile profile spend due to a small number of very large projects. We're predicting a steady increase in non-load-related expense to 2014/15. As this declines after 2015, there will be a significant step-up in load-related CapEx. This includes major investments in additional transmission capacity to connect the LNG importation, storage and new gas generation.
In total, we've estimated the cost of the gas transmission plant at GBP 8.8 billion over the 8-year price control period. This is, again, mainly driven by GBP 7.2 billion of capital investment with GBP 1.6 billion of operating costs as well. Overall, we believe this is a comprehensive and realistic plan to deliver safety, security supply and reliability and to enable the industry to meet the climate change targets. At the same time, the impact on customer bills is minimized, as Paul will share with you. We expect the transmission elements of a typical annual household bill to only increase by, on average, GBP 12 for both gas and electricity combined, compared to the current level in RIIO terms. Of course, this is all underpinned with the delivery of reasonable returns to our investors.
I'm now going to hand over to Paul, who has led the team responsible for the preparation and submission of these business plans. Paul is going to take you through some of the more detailed elements including, importantly, our financing submission. Off to you, Paul.
Thank you, Nick, and good afternoon, everybody. I'd like to start by reiterating what Nick said earlier about stakeholder engagement. Our program's being very extensive and has driven a number of changes to our submission. We have spoken to a range of stakeholders, including consumers, network users, government and investors. And the main message we received across the board is that we must continue to deliver network reliability and safety as well as balance the money. These discussions have also informed our views on return on equity and the other metrics required to attract new investments. As I'll cover in a moment, our plans assume funding at an individual entity level. This is very distinct from funding at a group level, and John will cover this later.
In the numerous examples for our own analysis and input from stakeholders, which helped us to identify key design features of the plan, one concrete example is one feedback we've received has led us to consider carefully our assumption on the proportion of new electricity transmission lines that will need to be buried underground within the jargon. This is a controversial area, and we've assumed 10% undergrounding in the plan, something of an increase on historic levels. But recognizing a debate continues, we've also proposed a mechanism to deal with the actual level that we're asked to deliver. As I said, our financing proposals also take account of the input we've received and I will run through these in more detail now.
But first I should remind you that, under Ofgem's methodology, we need to look at NGET and NGGT as notional companies funded by a set mix of equity index at an assumed debt interest rate. Which business the metrics we calculate, therefore, are those for this notional company and do not represent forecast about actual outturns or those of the wider group. In the second financeability, we also assume the company's achieved the base level of return with mutual incentive performance.
In putting together our proposal's revenue and financeability, we considered a number of targets, which we needed to meet. These targets included maintaining credit rating metrics at the suitable net offering A- rating, that's particularly FFO to debt and FFO interest cover; equity investor requirements, including support for appropriate dividend growth and the return commensurate with the level of risk; and finally and importantly, we considered the impacts on customer bills while delivering long-term customer value. When we looked at the levers available to us to find an acceptable financing package while meeting those targets, we looked at -- allowed return with debt and equity; assume notional gearing; levels of depreciation; transition arrangements and the capitalization ratio, and what I mean by that is the amount of spend treated as so-called fast money, in other words, OpEx, versus the amount treated as slow money, in other words, CapEx, added to the RAV. The Ofgem's decisions document in March applied some guidelines as to which of these levers we could pull, but Ofgem had not given guidance. We saw further input, and we applied our own judgment as to appropriate limits.
Now turning first to NGET, the financing proposal we submitted is as follows. The 7.5% cost of equity, 55% notional gearing and transitions of 45-year asset lives on new investments over the course of 2 price control periods. We also cap co-sharing factor under the incentive mechanism at 40%. In addition, our modeling shows the need for notional equity injections totaling GBP 3 billion into NGET over the course of the price control period. This allows us to achieve some notional gearing from the current assumed level of 60% and then to maintain it to an average of 55%. Again I should stress that this is part of the notional modeling and not reflective of anything required at the group level. It included an additional revenue allowance equal to 5% of the amount of notional equity injected within our submission in accordance with Ofgem's guidance. And these would inject new equity into the notional companies, one of the many drivers for our requirement for a 7.5% cost of equity, which is outside of Ofgem's range of 6% to 7.2%. Investor feedback has made it clear to us that the cost of new equity is higher than equity in the business that can sell fund for sustained leverage.
Other drivers which take outside of the range include longer regulatory period and related input price uncertainty and the scale of investment required and the related funding concerns. Our modeling shows that this proposal delivers what we will consider to be a financial outcome at a cost which is manageable for customers.
Turning to the metrics. At 60% gearing with no adjustments to asset lives, all credit rating ratios would reach almost continually. At first, we have to apply the transition arrangement and the lowered gearing we are proposing. The charts show the trend lines we used for fixing financeability. As you can see, the notional company is broadly in line with the limits required for an A- rating on the FFO ratios but remains below the PMICR ratio. We believe the strength of the regulatory framework will provide sufficient support for an A- rating, but we will continue to discuss this with Ofgem and the credit rating agencies over the next few months.
2009/10 prices, the level of allowed revenue for NGET increases under our plan to an average level of GBP 2.2 billion a year over the period compared to GBP 1.6 billion today. Electricity transmission costs represent around 4% of the domestic consumer's electricity bill, and the proposals would increase that to around 6%, assuming more transmission costs remain constant. This is an extra GBP 7 per annum for a domestic consumer.
For NGGT, the financing proposals we have submitted are as follows. As for electricity transmission, we propose a 7.5% cost of equity, 55% notional gearing and the cap on the cost sharing factor at 70% -- no, 40%. Gas transmission already has a 45-year asset life, and so a transition arrangement is not possible. However, our modeling shows that the notional company would not be financeable without some further support because of the size of the large key investment over the period relative to the cash generated by existing assets. To accommodate that, we have proposed using a capitalization ratio consistent with the relatively conservative level of investments, effectively excluding projects expected but not yet committed so that any additional investments above that conservative level attracts additional fast money over the period. In addition, at NGET, our modeling shows the need for notional equity injections totaling GBP 1.1 billion over the course of the price control period.
For NGET, our modeling shows that this proposal again delivers relatively tight ratios, but we believe it would still support an A- credit rating. 2009/10 prices, the level of allowed revenue for NGGT increases under our plan to an average level of GBP 1.2 billion per annum over the period compared to just GBP 100 billion today. Gas transmission charges make up around 3% of the domestic consumer's gas bill, and the proposals would increase this to just under 4%, assuming on transition costs remain constant. This is an increase of around GBP 5 per annum for a domestic consumer.
Proposals we've made to expenditure, transition arrangements and the split between fast and slow money all impact the expected growth in the RAV over the RIIO price control period. Drop baseline kind of assumptions, the RAV would grow to approximately GBP 24 billion in NGET and GBP 12 billion in NGGT on March 2021, representing annual growth rates of 11% and 9%, respectively.
Eight years is a long time, so as Nick mentioned earlier, our business plans have to accommodate considerable uncertainty. Our plan proposes a range of potential uncertainty mechanisms set out on the slide, and this include: revenue drivers to adjust for the timing and size of new electricity generation connections and the timing and size of new sources of gas supply and gas demands; trackers to cover large changes to input prices, such as the price of copper or steel; and as I've mentioned, a volume driver to respond to the actual level of undergrounding required for our new electricity transmission assets.
Hand in hand with uncertainty would go incentives, people look into earning enhanced returns as we reward for efficient management of the business. Our framework is designed to increase the incentives around delivering efficient outcomes. Our consideration of the required financial package assumes the uncertain mechanisms that created for situations such as those I've outlined earlier, and sufficient incentive mechanisms are in place to allow efficient and effective companies a reasonable chance to deliver enhanced returns.
I've given some details around the proposals we've made, our financial business plans. The plans we've submitted run to thousands of pages and cover many other topics. We'll be publishing a majority of this material on our website today. Any material we won't publish is found -- which is commercially sensitive. You'll have an opportunity to review this material during August. A number of members of my team will be available on a follow-up call on the 6th of September to answer your questions on the details of our submission once you had a chance to digest them.
I look forward to talking to you again. Then in the meantime, I'll turn it back to John.
Thank you, Paul. I hope you've found this a helpful summary of the plans we have submitted and can see why we think they are realistic in terms of the overall investment required and that they provide a sensible framework under which we can deliver stakeholder needs at the price that consumers can afford. My closing remarks are going to focus on 2 areas: to provide a group context for the long-term investment program that Nick and Paul have taken you through and to outline some of the group level considerations you should be thinking about when reflecting on the detail of these U.K. transmission-focused proposals.
In May 2010, we set out our GBP 22 billion group capital investment plan from 2010 through to March 2015. This chart sets out that program, reflecting our view on facing and updating for actuals and inflation. If you'll overlay that plan with the detailed elements of our RIIO gas and electricity transmission programs, you will see that the profile of our investments are we faced, push back a little from our earlier reports including changes in our U.K. distribution, U.S. and other business investments as well. Based on the RIIO submission, the overall investment in the 5 years from 2010 to 2015 would be expected to fall slightly to just under GBP 22 billion. A straightforward summation of the submissions for 2015/16 through to 2021, combined with realistic profiles -- realistic assumptions for the other areas of activity, provides the investment profile you see here. As you've heard, one of the key objectives of our submission is to embed flexibility into the EPA regime to ensure that there is an effective alignment of incentives with optimally delivered outcomes.
This has been demonstrated in the past. No matter how it -- as has been demonstrated in the past, no matter how well you plan to deliver for your 4 years out or even in the next 12 to 24 months, the final outcome will be impacted by the timing of connections, funding commissions and other events. This is particularly true when you add in 3 other lines of business, each with potentially significant investment needs. This uncertainty has been dealt with in some detail in our submissions to protect customers and investors. As Nick has said earlier, we have stress tested our plan against a number of other scenarios such as slow or accelerated investment in wind and nuclear generation. As a result, when you factor in these sorts of eventualities, we can see quite a wide glide path of investment outcomes through the RIIO planning period, all of which present very different funding characteristics and more that you consider this at the group level at the appropriate time.
All this talk about notional equity injections is part of the funding process to both NGET and NGGT of GBP 3 billion and GBP 1.1 billion, respectively, in part related to the change in the underlying notional capital structure as well as to support the significant growth in net debt that will develop through the imperative investment. Maybe these are equity injections into the notional operating companies and not equity injections into National Grid plc. We've already funded a large part of this with our rights issue in 2010, which supplies sufficient balance sheet strength at the corporate level to maintain appropriate credit rating ratios. As Paul stated, the very serious that we show -- the various ratios that we show for the notional companies are not necessarily those that we would expect to see from the actual businesses and particularly not from the group as a whole.
Our overall metrics will be significantly influenced by other factors. Around half of National Grid's total activities are much more steady state in terms of investment needs in the businesses we have talked about today. In addition, operating performance should improve in the U.S., investment in non-regulated activities will, by their very nature, be opportunistic, and we have a significant tail-off in CapEx towards the end of the decade. As a result, all other things being equal, we are very confident that we remain well placed in terms of our financial strength through to, at least, 2015. Looking beyond 2015, given the range of uncertainties and other outcomes across the group, we will have ample time once we have agreed our final investment plans with Ofgem to set out our longer-term financing needs.
Nick and Paul have outlined the key measures that we have been thinking about to insure appropriate funding and returns to both NGET and NGGT. As I have said, it is essential that the whole package, the profile of investments and proposed mechanisms to cash flows, capital structure and returns, revise our framework for sustaining and attractive investment proposition through our equity investors, based around the combination of healthy dividends and equity value growth within the business, also maintaining appropriate credit ratings. In this context, we would ask you to reflect on the importance of how the different tools in the plan have to work together to create a program that is realistic in terms of scale, affordable for the consumer and attractive for equity and debt investors alike. The cost of equity, capital structure and transition arrangements are an integrated solution to these challenges. As a result, changes to individual elements will probably necessitate adjustments elsewhere if this balance is to be maintained.
Following today's publication of the plans, we expect feedback from and further engagements with stakeholders. Ofgem will publish their initial review of the plans in October. As you know, we are keen to be as transparent as possible with you throughout this process. To that end, we will be holding another call on the 6th of September to focus on your key questions with more time for questions and answers. We will send out details of this call in due course.
Thank you for your attention. Now I will hand you back to the operator for your questions.
[Operator Instructions] And we'll take our first question from Bobby Chada from Morgan Stanley.
Bobby Chada - Morgan Stanley
Two questions. The first is can you, is it possible to break down for us the split of the revenue that you've requested in the business plan between July underlying regulatory revenues, financeability-related revenues and transitional arrangement-related revenues to give a feel for how much those financeability and transition arrangements contribute to what you've requested? And then secondly, on the rollover proposals, which were published a day or two ago, I noticed that the CapEx and the RAV numbers seemed to be substantially lower than the numbers that you've talked about. Is that simply a logging up issue? Can you explain the difference between the CapEx in the document and what you've discussed with us previously?
Thank you, Paul. Why don't I ask Paul to tackle the first part of that question and Nick to do the second part?
So, on the first about breaking down the revenues between those different buckets. I don't think our business plan is set out in those terms. I mean, my easy answer to many of the questions will be, you've got all the detail available on the website this afternoon. I don't have the sit-down in that way. So perhaps we'll take that away and have a look at it and see if we can represent the information in that way.
Bobby, on the rollout, what's quite clear from see the words from Ofgem is that there's quite a bit discussions still to go. I mean, I think I understand a bit both organizations, which sort of we're focusing on RIIO. And so there is a substantial debate still to be had, which I think, Ofgem generously signaled about the OpEx and CapEx levels. Paul, do you want to pick up the detail point on [indiscernible]? I mean, what I want is clearly quite a few discrepancies in terms of the specific definitions of what we've included in the CapEx figures you see in the RIIO submission versus those that are actually there with in this initial proposal from Ofgem under the rollover review. And I think there are some various aspects of anticipatory CapEx et cetera and incentive-related CapEx. So we would've put into the buckets in our general submission but which are not actually addressed in this particular detail document that Ofgem had put out. I don't know, Paul, you want to add anything else on that?
Well, not really. I think you've covered the point quite well. I mean, I suppose, in summary, we're still going through the numbers, as well. And I think we'd probably need to have a bit of a chat with Ofgem to make sure what we can square all the numbers up. But I don't think we're seeing a sort of a missing bit of RAV anywhere. I think it's just a question of reconciling things that are in different buckets into a sort of common format. So still a bit of work to go on that, I'm afraid.
Well, did that give you a satisfactory answer?
Bobby Chada - Morgan Stanley
To a certain extent, yes.
You will follow up, I think.
I think it's the best that we can say. I mean, the level of detail in these disclosures and the actual definitions that they used do then get mixed up a little bit, and that's one of the problems we're seeing with the Ofgem review.
Bobby Chada - Morgan Stanley
Okay. I mean, this isn't, it's an unusual difference, I would say, in terms of its -- the order of magnitude.
In terms of our preliminary announcements, we think it's fairly accounted for. We just haven't got all the facts and figures in front of us to be able to present them simply and in a logical way, quickly on the calls. So I think the best thing we can do is to follow on more generally when we've actually set out the appropriate schedules and also confirm that these are right in relation to what Ofgem was attempting to say in its document on Tuesday.
Yes. But sorry, at the risk of keep on coming back at this and showing -- there absolutely are 2 different elements here. There's a question of reconciling things into the same buckets, which accounts for some of the difference. So some things aren't in the Ofgem numbers that were in ours and are sort of acknowledged as not being in there, not in the sense that this is allowed. The things like anticipatory spend may not be included in those numbers. So then, but there are also then definitely as well as just a question of are the buckets then compare to the same ones, there are also then still areas where Ofgem is saying they require more evidence, that’s particular investments need to be done and, in particular, that they need to be done in that particular year. So there's a big timing question about, in particular, some of the non-load investment, which clearly is going to be inevitably, with RIIO being such a long period, is a measure as well. It doesn't appear in the rollover year, it just appear in RIIO because, together, these take long period of time in the context of assets that have a 40-year life. This is about a quarter of it. So things that ultimately don't get there in the rollout will inevitably fall into rear. We'll try to give you some small color on that.
Our next question comes from Mark Freshney from Crédit Suisse.
Mark Freshney - Crédit Suisse AG
You mentioned that the base case is modeled around the Going Green scenario, which I guess match to Ofgem's Project Discovery green transition roughly. But given what we've seen with your end customers recently deferring investment decisions and so forth, the scenario that we've seen is more like the dash for energy. And other such a scenario, is it fair to say that the CapEx would be towards the bottom of those, if you light those columns, on the scenario analysis that John presented at the end?
You can reckon that the Gone Green scenario is very much like the Discovery scenario. I'm sure there are differences between them, but they wouldn't be very significant. And that Gone Green scenario, of course, had a wide airing, not only through the stakeholder process but also it was accepted by ENSG, the group with Ofgem and deck on it that looks to anticipatory spend, so we are working broadly to that. I think you make an interesting point about, well, is the current evident that Gone Green is playing out there [indiscernible]. And my answer to that is, no, not clearly, but you wouldn't certainly expect it to be because critical to playing out Gone Green is EMR, and while the market perform proposals are still being debated and rightly with urgency, it's going to be difficult to see the generators committing completely through to FID to a lot of the greener end of the generation mix that we look and see. The final comment though is, of course, we talked about during the equity raising last year. It's quite noticeable that even if you move to a sort of slow progression with, if you like, gas filed CCGT, taking more of the strain in terms of new plant coming on the neutral wind with neutral wind going backwards. It's noticeable how little difference it actually makes to our projected capital spend. What it does is it moves it around. It is, I mean, to take CCGTs, we don't connect them up for free either. If you look historically at the amount of money that’s spent to connect our CCGTs, you still get very significant spend. So in essence, almost whatever, I think, this is very, very fair to expect that the coal and oil to close down. That's almost certain, I would say, to the Magnox. So whatever replaces it is going to mean significant investment by us. And the CCGT one is fascinating in a sense that whilst you might well see a slightly lower level but still significant spend on the electricity system, we end up with a load of spend on the gas system to connect up the CCGT to the gas networks. So it's sort of moves around in our portfolio, and that's why we think it's absolutely critical to have very, very well-worked uncertainty mechanisms, which then the revenue -- further development of the revenue drivers, so that the thing automatically adjusts for those different scenarios.
And I'll just add a couple of points. I mean, just going back to the points that we sort of made in presentation, I mean, we are smoothing our workload on the electricity plan use in the non-load. So to the extent that's our force is taken off, doesn't lead to -- make effort on the load stuff. We will be able to bring forward the non-load to the balance of the workload over a period of the plan. And I think the other thing that's kind of come up over the last year, particularly as we'll be now thank trying to move some of these new transmission circuits, is the question of undergrounding. And although we put a slightly higher percentage of undergrounding in our plan, you shouldn't be in any doubt that there are a number of people out there who prefer to see some undergrounding a lot more of our transmission lines. That will tend to increase expenditure. So that number factors that you're sort of balancing across the overall plan here.
Mark Freshney - Crédit Suisse AG
Okay, thank you. And just a follow-up question regarding the 2 HVDC links because I guess and those are subjective and there may be alternatives. How much of those or what's the quantum of the CapEx for those?
We're on the -- the western one the most well develop since. And of course, Ofgem has been looking that recently. And that's around GBP 1 billion. That's the total cost, which is obviously split between our Scotia parallels and ourselves. That's pretty well developed, and Ofgem have considered that and broadly with some understandable caveats about more shrink progress that broadly given that, the green light to proceed through to deliberate for 2015. The eastern end connector must get the actual capital cost and so -- but that's just back slightly in the process of discussion with Ofgem. I think we’re agreed that the western one should go forward first is contained in the RIIO plan.
And we'll take our next question from Jamie Tunnicliffe from Redburn Partners.
Jamie Tunnicliffe - Redburn Partners LLP
I wondered if you could just set up -- obviously, as you've clearly highlighted in your slides, the credit metrics are quite important in determining the whole profile of revenues. Can you just talk about the individual credit metrics that you've used? Which ones matter most? What's the constraint level that you've used in taking these judgments in your business plan and the proposals? And on a second question, which is just in terms of that question that was asked earlier on in terms of the rollover, as you pointed out, you said there's potentially some issues about sort of base costs and then maybe some extra costs where obviously doing additional things where Ofgem seemed to have come back and said they require a bit more evidence that you're going to have the ability to provide between now and November. Do you have any feel or could you give us any guidance sort of on how the difference between sort of what you've asked for falls between those 2 categories?
So I'll go to the credit metrics first. I mean, I think there is a lot of detail in the way that we've done the calculations set out in the documents that are going to be on the website today. To stand back from all that detail, this is a sort of broad judgment thing, so we have sought to sort of take Ofgem's guidance on where they think the credit metrics will also be set. We've compared it with our understanding of the approach taken by the various rating agencies, and then we have to look at how those credit metrics kind of adjust under a range of different scenarios. Now all of that is going to set out in quite gruesome detail on the plan, and I think I'm going to refer you to those, if you don't mind.
Jamie Tunnicliffe - Redburn Partners LLP
Can I ask, what have you typically found to be more binding of the sort of 5 or so credit metrics that are seen to be the most important?
Well, I mean, the one that we've sort of struggled with the most is, I think, I've sort of alluded to as the sort of the PMICR, the adjusted ratios. It was sort of immune to transition measures. So I think that's been one that we sort of have to work hardest to live with, if that helps.
On the rollover, just to give you a flavor of some of the stuff that's certainly for a significant further discussion with Ofgem as we come to the next couple of months. The load-related is reasonably a good alignment actually, I should expect at this point. The cuts appear to be around non-load, which will be a question, a legitimate question for discussion on timing, obviously, although we will certainly evidence very strongly that if we're to avoid a significant bow wave of asset replacement building up, that we really need to get cracking. I know that's a sort of temptation to want to hold it back to RIIO, but we can't afford that bow wave to build up. We will be assessing that strongly. Also on non-loads, there is the old chestnut in these discussions of unit costs. So those have been field days when there's always a debate about unit costs. So volumes tend to be easier to agree. We will be going back with very strong arguments about unit costs to deliver the volumes that are there. There was a significant amount of IT investment that's not been included. That was quite a bit of that was all about sort of some of the sophisticated IT systems that we'll need for balancing wind power on the system, greater intermittency, more frequent forecasting of where the system is going, sort of that type of IT, which we will argue very strongly that we really do need to get on with this if you look across Europe, the difficulties that the utilities are having with very significant amounts of wind on the system. One of the lessons we must learn is that we still have time to make sure that we can manage this in a very professional way, but we need to be free to get on with that and invest in significant IT to make sure that we can keep the system stable as we get to increasing that to renewables. So we will be arguing that strongly. On gas, a big cut in network flexibility, which is a -- and I have some sympathy for Ofgem on this. This is a very important part of the discussion we'll have as part of RIIO. It is all about essentially saying that, with intermittency coming off of the system we're going to see gas-fired electricity generation need to ramp up and down very fast to cover intermittency. That will create not capacity constraints on the gas system but the ability to, if you like, increase the throughput on the transmission system, gas transmission system, very rapidly as you see gas pipe generation replace wind. It's also about the quite significant change to the supply characteristics of gas itself. So the UKCS used to be predictable and growth to be steady when you had losses offshore that were relatively small. That's not the situation we're in now. We have a very good diverse and plentiful supply of gas into the country, but it's very different. And what we're seeing is when, for example, you get, as we did last winter, significant loss on the Norwegian continental shelf, we're seeing very rapid ramp-up from LNG importation service. So this is all about us needing to make that case very strongly and give a lot more evidence to Ofgem that, that need to create a faster reacting gas network as well as one with adequate capacity is legitimate, and we will be coming forward with substantial new evidence on that for Ofgem.
And we'll take our next question from Peter Atherton from Citigroup.
Peter Atherton - Citigroup Inc
A couple of groups of questions, really, couple parts. Just on the nominal injection of equity in the opcos, did you just confirm how you model that in terms of timing? Is it all going into 2015 or 2016, or do you sort of stage it? And I know it's not part of this presentation, but could you give us a feel for whether you think any of your other businesses like U.K. gas distribution or the U.S. also need nominal increases in their equity within this sort of timeframe?
Yes, Paul, why don't you take the first part?
Well, on the timing of these notional injections, we're putting a bit in at the start to get from 60% to 55%. And then I think all of the rest of it is after 2015, and then each is kind of sensitive to the actual phasing of the CapEx within the plan. So under the baseline plan, it's after the time scale under different versions of the plan. It will be at slightly different times.
Yes. And so inevitably, it just tends to move with the individual funding requirements after the necessity to maintain the gearing structure that we're proposing in all of this, and therefore, there is an interplay in that. But broadly, it's a small amount to get down 15% right at the start, and then the sort of it is in the second half of the decade. And the numbers will be in the finance bank, so you can put, drop them out. And as I made the observation later on in the presentation, Peter, the other businesses generally present much more steady state characteristics in terms of long-term funding. They're less lumpy, and the need for heavy investment isn't there in the same way. Clearly, nonregulated activities are quite discreet in nature, and whatever do you there, you're going to be injecting equity to build a business depending on what nature it has. So in the concept of these being notional equity injections, you move equity around the business in order to present the funding opportunity that individual businesses need. I guess the bigger question, which we were trying to address at the end is, when you collate that together and look at it as a group, what does it really mean for us a group in terms of the equity and capital structure for the business? And that's why we really say it's too early to really determine at this point in time until we've gone through to the end of the RIIO process and looked at the needs of the other businesses as well, what the potential situation will be for the group beyond 2015/16. It's not to say this can't happen, but it's not to say they'll also be significant or indeed actually relevant to our overall group capital management.
Peter Atherton - Citigroup Inc
And my second question is really about your capacity or the risks that you face in this big step-up in CapEx because, at a group level, you'd be running from sort of, going from GBP 3.5 billion a year to potentially up to GBP 7 billion a year within 3 or 4 years from now. Can you take us through how you're going to manage that step-up in terms of supply chain? What the risk are in terms of inflation and crucially, where you think the biggest bottlenecks might be in terms of skills, equipment or whatever?
Yes. So Peter, the supply chain issues, we think we're well on top of. We, as you know, have had alliances and coalition-type framework agreements with the major supply chain companies for some years, and we are very, very grateful that we took that initiative and established those long-term relationships because as well as mobilizing a great resource, the detailed design, which we have captured by having those arrangements. We've also managed to signal to the supply chain to allow them to increase their capacity on the basis of our forecast. Of course, merely tendering individual projects doesn't have that characteristic. It's very hard for the supply chain to justify those investments. So we're very happy with that. We've come to the reelecting of the principal electricity alliance arrangements this autumn, which we'll be going through into process, but broadly, we will continue with those supply chain arrangements. That's not to say there aren't issues in the supply chain. In particular, we're all, I think, very aware that supply of HV cables continues to be very thin on a global basis. The ability to get enough cables through the system is well known, and we're working hard to make sure that we are right in front of the queue on that. In terms of recruiting, these plans do show significant recruitment, 1,200, electricity; 400, gas. So I'm happy to say we're well on top of that. But the thing that should give you real comfort is that, that isn't us just saying, "Okay, Ofgem, we're proposing to do this in the RIIO period." We've already started very significantly. We have invested. It takes up to 5 years to get people through and to make them competent to really deliver. And so it was important that we ramped up early. We have done last year. We recruited 381. This year, we'll be recruiting at the order of 500. So we're not just, if you like, pitching this into Ofgem and seeing what happens. We're well ahead of the game. We're investing in new training facilities or extension to our training facilities. We're leaders in terms of -- we were the leading company in terms of foundation engineers. Our apprentice programs are graduate programs, are all stepping up. In terms of inflation, we will be putting forward, as one of our uncertainty mechanisms, specific indices associated with the principal commodity costs. So they are already in the plan and are quantified in the plan, the real price effects that we see and the sharing of risks between customers and shareholders that we're proposing to mitigate those real prospects.
I would make one final observation, Peter. You touched on the idea that when you looked at the modeling of the uncertainties chart, that CapEx can go from GBP 3 billion to GBP 7 billion. The Slide 28, when you look at the path, which gives you the solid bowl of how things roll out when you take the baseline plan and overlay it with city states. All realistic objectives for the old businesses really gives you, in many ways, what I would regard as upper limits and this also confirm the belief scenario that the accelerated investment phase could occur in the U.K. around wind and nuclear, rather more of the progression or the baseline business plan which we are presenting here to Ofgem, so you really need to factor in your old personnel position. So whether you see a slow progression as a more realistic outcome in which case you should be looking towards the bottom of those channels rather than the top.
Peter Atherton - Citigroup Inc
Yes, sure, I was just using it as the top-end number.
Yes. Well, I mean, in that sense, as an uncertainty, I think it's one which there will be -- you need to take some sort of adjustment on.
[Operator Instructions] And we'll take our next question from Edmund Reid from JPMorgan.
Edmund Reid - JP Morgan Chase & Co
Two questions. Firstly, in terms of the dividend policy of the opcos to the holdco, I wonder if you could give us any detail on what you assume in terms of maybe payout ratio. And then second thing, in terms of your modeling, how would you look at SO profitability going forward?
Okay, so on dividend policy, for modeling purposes, we have assumed that the opcos pay up 5% of the equity RAV, equity share of the RAV as it did within each year. So that may not be -- that's pretty straightforward. In terms of SO profitability, I think these numbers on the whole are without sort of SO impact filtering in as they basically represent TO [ph] plans.
Edmund Reid - JP Morgan Chase & Co
Okay, but I was just thinking in terms of...
I mean, it's on an SO investment, but you're talking about SO incentive ratio, are you?
Edmund Reid - JP Morgan Chase & Co
Well, yes, just in terms of historically you've performed quite well under the SO incentive schemes, which, I imagine, stay within the opcos. So isn't that another potential area of, I guess, sort of equity financing?
Well, the SO costs so in terms of CapEx and OpEx. Obviously, they will flow through the submissions and so you should regard those as having incentive arrangements the same as the TO [ph] essentially. So that is modeled in. The incentives, we haven't modeled in because they are symmetrical. Ofgem very keen to make them be symmetrical indeed. Some of them seem to be tending toward small stagnant carriers. So assuming overall neutrality in that, you can -- obviously, we will endeavor, as a management team, to deliver strongly, but they shouldn't be regarded in any sense as a further source of funding that will be baked in to these plans. They can deliver well or obviously they can serve it less well.
Gentlemen, there are currently no questions in the queue at this time.
Okay. Well, then that brings us quite well to our one-hour conference call. So if there are no further questions, can I just thank everybody for taking part, thank you Paul, thank you nick for their contributions. We are holding another call on the 6th [September 6, 2011] as we said. There are a large quantity of materials that people can take to the beach with them over the summer, if they wish. And hopefully, they will have other questions next session which the team can tackle. We're also doing quite a few different investor activities, which we'll set out with some communications during September. So there will be lots of opportunities to meet with the team and to talk about these things in more detail, and we look forward to engaging with all of our investors and analysts in due course. Thank you, all, very much for taking part.
That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.
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