康涅狄格電力 (ES) 2006 Q3 法說會逐字稿

(Audio joined in progress) Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward-looking statements.

Factors that may cause actual results to differ materially are included in our forward-looking statements, and are actions by state and federal regulatory (indiscernible), competition in the industry, restructuring, changes in the economic conditions, changes in weather patterns, changes in laws, regulation or regulatory policy, expiration or initiations (indiscernible) energy supply contracts, changes in levels of CapEx, developments in legal or public policy doctrine, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, the method, timing and results of the disposition of our competitive businesses, actions of the rating agencies, tariffs and taxes (indiscernible), presently unknown or (indiscernible) factors.

Other risk factors are detailed from time to time in our SEC reports, and we undertake no obligation to update that information in any of our forward-looking statements to reflect developments.

I'm going to move on from that thrilling readthrough and I'm going to introduce Chuck Shivery, our Chairman, President and CEO.

Thanks.

Good morning.

Thank you very much for joining us.

Thank you, Jeff.

I want to do a few things today.

I guess the first comment is, boy, what a difference a year makes.

When we were here on November 7 with a number of you last year, we made a fairly significant strategic announcement.

The stock was in the high 17s, I guess, at that time.

And I think we've been reasonably successful as we've gone through the strategic direction that we undertook at that period of time.

I want to spend just a little time talking about '06 results and guidance.

We will update you on our strategic transformation, give you some additional '07 guidance, and then get into a discussion of the capital expenditures that we see over the period '07 through '11.

And then we will provide you with some more color around those capital expenditures, specifically what are we actually going to do that will require those dollars, and then ultimately what will be the outcome in terms of the earnings on those dollars.

After I finish, I'll turn it over to Dave McHale, our Chief Financial Officer, who will go into more detail around capital expenditures and earnings.

After David will be Cheryl Grise, who heads up our regulated distribution and regulated generation businesses.

And then Lee Olivier, who is in charge of our Transmission business, will tell you some of the things that we're going to be doing in Transmission as we go forward.

'06, both the third quarter and year-to-date have been strong.

Clearly the biggest reason for that is the private letter ruling that we discussed with you at the last earnings conference call, which added $0.48 to earnings, both in the third quarter, but also year-to-date.

Our regulating and parent guidance is now $1.57 to $1.70; that is unchanged from the last discussion that we had with you when we did our second-quarter earnings conference call.

And if you strip out that $0.48, the guidance is $1.09 to $1.22.

This was the guidance that we gave you this time last year, and we are continuing to keep that guidance in place.

So '06 is headed pretty much right where we expect it to be and very consistent with the information that we gave you on the second-quarter earnings conference call.

If we step back a year, we said were going to do two things.

We were going to divest all of our competitive businesses and we were going to focus on the regulated utility infrastructure and the capital necessary to produce the kind of infrastructure necessary for continued reliability in the regions in which we operate.

That was announced on November 7, 2005.

We also showed you a graphic at that time that broke the Company into two pieces, the regulated component and the competitive component.

The regulated component, which was shown in blue, were those businesses that we would retain and grow.

And the businesses shown in green were those businesses that we anticipated exiting over 2006.

As you can see by the dates in the boxes of the green, we sold retail on June 1 of 2006 to Hess.

We had gotten out of the wholesale New England contracts before the beginning of 2006.

As many of you know, we just closed on the generation sale, which was $1.34 billion on November 1, and we have in fact sold five of six services businesses.

There are a few things that are left for us to accomplish over the rest of this year; but essentially, by the time we begin 2007, we will be a holding company that holds four regulated utility companies.

The second piece of that strategic decision was to invest capital in regulated infrastructure.

This graphic shows you in two places -- it shows you the amount of regulated capital expenditures from 2004 to 2006 estimated -- you can see the increase there.

It also talks about the status of the major projects.

We just announced that we have completed the Bethel to Norwalk transmission line; that's a 34,521 mile transmission line, some underground, some above ground.

A number of you joined us a few weeks ago at the Norwalk substation, where you got the chance to see gas-insulating switchgear, a transmission substation.

Those kinds of things are really interesting because what you hope that happens is that nothing happens -- when you walk in there, there are no moving parts, there are no flashes, and that was actually the case.

I am disappointed though.

We gave you some, I thought, very, very cheap clothing to wear at that and nobody brought that with them for this breakfast.

Although probably, as someone suggested, it may have been difficult to get on the airplane with that clothing.

Anyway, Bethel-to-Norwalk is 100 percent complete.

The important thing about the other three major Southwest Connecticut projects is that they are under construction.

Lee will go into a little more detail on exactly where we see those projects.

But we continue to move, I think, expeditiously on all those major transmission projects.

On the distribution and generation side, Northern Woods -- that is the 50-megawatt power plant that we switched from coal to wood chip -- is in final testing and we expect that to be completed by the beginning of next year.

And the Waterbury LNG plant is about 85% complete; we expect that finished and up and running for the heating season in 2007 and 2008.

So as we told you a year ago, these are the things we're going to do, and on every quarterly conference call we will give you an update so you can see exactly how we are tracking against the objectives that we set forward.

And I think we've done a pretty good job on that.

We also said a couple things, when we decided to transform this Company.

We said it will have some benefits to this organization; it will simplify our business model and strategy.

It will reduce our business risk and improve our financial flexibility.

We will capitalize, we think, on the increasing valuation of generation.

Clearly our earnings disability is enhanced.

And we will focus on regulated infrastructure.

I believe every one of those has been validated.

Many of those have been validated by our investors, many of who are in this room today.

Clearly, we do have a simplified business model.

You will see, not only from last year, but again, today, you can track capital expenditures, you can track rate-based growth and, assuming reasonable regulatory treatment, you should be able to essentially develop a pretty good earnings forecast.

I think business risk has come down.

In fact, Standard & Poor's just reduced our business risk from 5 to 4 just recently.

The $1.3 billion sale of generation clearly allowed us to capitalize on that valuation, and we do believe that the Company is much more transparent and the earnings visibility is much greater.

And David and Lee and Cheryl will give you some additional color around all those drivers for earnings.

We're going to continue to expand the capital program.

In fact, the capital program for this five-year period is larger than it was for the last five-year period.

And for the four years that overlap, 2007 to 2010, it is significantly increased.

What we've shown you in this graphic are the projections for those years that we showed you in November of last year.

And what we are now showing you are the capital expenditure projections.

Significant increases.

As that flows through the system, you would expect to see changes in earnings associated with those increases in capital expenditures.

And David will go through that in a lot more detail in just a moment.

This is a slide that we've used before, but updated.

It shows you the rate base by various segments of the Company that we expect to have at the end -- or had at the end of 2005.

That rate base is $3.3 billion -- or was $3.3 billion.

If we can execute around the program we are going to lay out for you this morning, our rate base will be very close to $8 billion by 2011.

More importantly, the diversity of that rate base will change.

And in fact, instead of having transmission at 18% of a smaller rate base, we expect to have our transmission rate base at 38% of a much larger rate base.

Distribution will shrink just because of the growth of transmission.

Although, as you will see, there are significant capital expenditures going into the distribution and the regulating generation side.

And gas is a little bit smaller.

What does all that mean?

Well, it means a couple of things.

We're giving you guidance today that '07 will be $1.30 to $1.55 per share.

We're also saying that we think that the compound earnings per share growth rate for this Company for the five-year period beginning at the end of this year -- I want to make sure we're clear on that -- we're calculating that growth rate from essentially the midpoint of '06 guidance without the PLR.

So the $1.09 to $1.22, take the midpoint of that and look forward, and we believe that the compound earnings per share growth rate of 10% to 14% from that period of time is an appropriate growth rate.

A lot of moving pieces still.

We will keep you apprised of that as we go forward.

But as you can see, if you simply take the midpoints of where we expect to be in '06 and where we expect to be in '07, it's a little over 20%.

There is a shape to that growth rate; it's very consistent with the shape that many of you have seen for the previous information that we gave you.

Clearly, the capital expenditures are going to be greater in the first few years, and we would expect correspondingly the earnings growth to be greater in that same first two years.

The last point on here is something we get asked a lot about and it's dividend policy.

I think the way that we'd like to begin or continue to look at this Company is really a total return to our shareholders.

We have a very attractive growth for the next few years.

While we're in that attractive growth period, we think the dividend policy that we have in place right now is very appropriate.

As we move out and as those expenditures get into rate base and as the capital expenditures may decline slightly or slow down slightly, we think it clearly gives us the ability to change the dividend policy, certainly look to changing the dividend policy at that point in time, so that the total return to our shareholders is very attractive over the whole five-year period of time.

NU has a very large presence in New England.

We are the largest transmission-owning IOU in New England.

The majority -- I think it is about 55% from the last presentation -- of the ISO-identified transmission need is in the NU franchise.

We are building that.

We are clearly a leader in transmission technology.

We are one of the largest landowners in New England, which gives us the ability to utilize that land if generation opportunities arose or to potentially harvest that land if it's not any longer needed.

And clearly, we're the largest electric retail and distribution utility in New England.

We will provide a leadership role in New England around energy policy and around the kinds of things that are necessary to make sure our customers get the electric distribution and delivery service that they need.

I want to spend just few moments on this last slide before I turn it over to David.

And it's really about what is not in this projection.

If you look at that capital expenditure program, you see very large capital expenditures (indiscernible), slowing down a little bit before the latter parts of the five-year period of time.

There will be, we think, additional transmission opportunities in that latter period of time and extending past 2011 that are not in this model.

And Lee will talk a little bit about those.

We believe there may be regulated generation opportunities, whether that is a new woodchip plant in New Hampshire or whether that is a (indiscernible) unit in Connecticut.

None of those are modeled into these numbers that we're talking to you today.

And some of you have heard me talk about what I think is going to be a real potential change, at least in certain geographic areas of this industry, and that is around energy efficiency, demand-side management, dynamic systems.

One of the things we've got to do is figure out what title we want to call these.

But technology is really changing.

It's changing rapidly and it's going to change the way that people and utilities think about energy efficiency, or maybe a better way to say it is more effective utilization of the energy product, whether that is gas or electric.

I don't know what that means at this point in time to us, but I know if those technology advances happen, it will give us opportunities that we don't think about right now that are not in this planning period.

It will give us opportunities to change the way we think about our interaction with the customer.

And I think it will give us opportunities to better utilize the electrical energy infrastructure for our customers' benefits.

Those are not built into this forecast.

I think they will unfold over the next few years, and as they do, we will certainly keep you apprised.

Let me now turn it over to Dave McHale to go through the financial part of the presentation.

Thank you, Chuck, and good morning.

I'd like to start by adding some additional perspectives to our earnings that I know that you've seen this morning.

First, for our nine-month results, a couple of non-recurring items in here, but clearly the largest driver is the fact that our competitive businesses have been almost fully divested now.

And the far side of this graph, as you can see that for the first three months to the first nine months, we have earning $123 million versus a very substantial loss last year of almost $240 million.

And in the middle of the page, you can see that shift, although for the first nine months this year, we did lose $73 million.

And that is mostly related to the sale of our retail business.

We knew that business had contracts that were out of the money; we knew when we were going to sell that business that it was going to be a loss; it's no surprise to us.

Hess bought that book of business, and that is really the majority of the $72 million that we lost.

We'll give you, actually, some direction for what we think is going to happen in 2007 as well.

On the other side of the graphic, though, you see the $150 million that we've earning in the distribution business.

That is largely as a result of a reduction in (indiscernible) these taxes this quarter, that $74 million PLR, Private Letter Ruling Benefit that we began to talk about last quarter, that's a non-recurring item.

But let's not look at the smaller bar here, $43 million for the Transmission business is up almost 50% over last year's performance.

Let's look at the quarter a little bit more closely.

We will stick with transmission, $18 million for the quarter versus $11.8 million; that's a 54% increase relative to last year.

That is story is working and that story is increasingly about executing our projects, getting our capital into service and growing rate days.

We will show you more about where we're going forward, but that idea is the net business unit is working for us quite well.

When we look at regulated distribution and generation, the quarter-to-quarter earnings are up substantially.

That is the $74 million, that is the $0.48 related to CL&P's non-recurring reduction in taxes.

But after that, we see that the quarter is actually off somewhat relative to '05, primarily because sales are down, electric and gas sales are off this quarter about 4.5%, only 1.8% sort of weather normalized.

And we actually did as well -- when we were having warmer summer weather driving sales, we had some storms.

We talked about that earlier in the year, as well.

That storm expense landed primarily at CL&P, created a little soft of a quarter.

Nevertheless, as Chuck suggested, we are affirming guidance at the $1.09 to $1.22 range.

We put some color commentary around this segment.

Here for the distribution companies, we said we'd be at or slightly below the $0.75 to $0.85.

And that is driven, again, by sales and some of the costs on the O&M dollars that we've seen as a result of some of the storms.

Transmission will earn in the $0.34 to $0.37 range.

And I should tell you, too -- Lee will spend a little bit more time talking about the ROE order that we received from the FERC.

That ROE order will actually cost us a little bit in 2006 because we had been booking earnings since March '05 at about 11.5%.

That order allows us to earn 10.2%. 10.7%, depending on what segment of assets.

So we expect to take a charge in Q4 of this year of about $3 million to $4 million in the Transmission segment.

It will be about a $1 million pickup in the distribution business, because they will actually receive a benefit primarily, from PSNH.

But with that said, Transmission still comes in the $0.34 to $0.37 range.

Parent, we have said earlier will be at breakeven.

We think it might be actually slightly above breakeven at this point.

Nevertheless, $1.09 to $1.22.

The new news here then is 2007 guidance.

We first signaled in August that we were comfortable with where the Street was, $1.30 to $1.40.

That midpoint of $1.35 compares now to this midpoint of $1.42, $1.43, so we are coming in even a little bit better than we had seen this summer, and partly because of the capital and the rate base additions that we've seen in Transmission.

I'll go through some of the drivers.

So we've got segmented guidance now $0.80 to $0.90 for the distribution company; that is up.

We've got guidance of $0.50 to $0.60 for the Transmission company; that is up substantially.

The parent, we think, is going to be a little bit better than breakeven; we think it will be 0% to 5%, and I'll elaborate in a moment.

And although we haven't given guidance for the competitive companies in 2006, we are giving you guidance here that we think it's going to be a breakeven business for the activities that remain, the residual activities and exposures that remain in that business.

All in all midpoint, '07 to midpoint 2006, 25% increase in earnings.

A couple other drivers, and let me start with NU parent.

Even though we are predicting that earnings will be zero to $0.05, I think it is worth saying that it's in large part because we are sitting on cash, cash from the sale of our assets.

We closed that just several days ago.

We have over $1 billion safely parked in the bank now, earning interest income.

And that offsets interest expense as a parent that you would normally see, as well as some O&M expense.

We also have a couple of corporate share services companies that earn money that are billed to our utilities.

They happen to be housed in the parent, but collectively, that business will be profitable in 2007.

I should say going forward, though, as I'm suggesting, that it's atypical.

More typical is that collection of companies, NU parent, would lose about $0.10 a share.

So when you're modeling going forward, I think a loss of $0.10 a share, once we fully utilize this cash, is probably something that would be wise to model.

For the competitive businesses, we will retain going into 2007 some wholesale contracts.

You know from our prior discussions that those wholesale contracts are largely hedged.

We will have mark-to-market exposure on them.

We do have some supply positions as well that are in the money.

So collectively, I think it is roughly breakeven.

We will retain some exposure on mark-to-market, but I don't think you should expect a great deal of exposure going forward.

On the Transmission business that is primarily about rate-based growth.

CapEx, planned service, then growing rate base.

We have the answer around the New England ROE now.

We are still in the process of analyzing that; we will give you a little bit more color commentary.

I think while there is a little bit of a drag on 2006 Q4, I think going forward, relative to what we've shared with you in the past, there's actually some uplift.

And that is built into our 2007 guidance.

And I think, on average, our ROE for the transmission business will be roughly an 11.8, 11.9 composite range for 2007.

For the Distribution business, that is probably where there is a little bit of volatility.

Our range is 80 to 90.

We've got a couple of key business drivers.

There, too, our increasing rate base and adding CapEx to the story.

Our organic growth in terms of electric sales, gas sales is up about 1%.

So still not a lot of growth there.

Although this year we're seeing some erosion in sales, we are projecting a little bit of an increase -- again, about 1%.

A little bit greater than that for gas; a little less than that for power.

So the real issue here is our regulatory activity.

Cheryl will go through this in detail.

But clearly, we already have a settlement for the Western Massachusetts Electric Company.

That settlement has to be approved, but that should drive new revenues going into 2007, and we think that puts us in a position to earn that 9% to 10% range.

PSNH, as you know, is in the midst of a case.

They already have revenues, at least temporary revenues, in place.

We expect new revenues, then, to flow into 2007, lifting earnings.

Same thing for Yankee Gas -- they'll file a case.

So we'll have new revenues in three of our jurisdictions.

CL&P, we will not have new revenues; we will not have a rate case, so that will continue to be a little bit of a drag on the overall distribution results.

The positive, though, is I think we go into 2008 coming off a rate case.

I think there will be very substantial improvement in their financial performance.

On the second-quarter call, we told you that by the end of 2006, we saw their regulatory ROE in the 7% area relative to their 9.85%.

That has authorized.

I think as we work our way into 2007, that ROE will drift into the low 6, mid 6 range.

And it's the improvement, then, year-over-year into '08 that I think will give us a very strong performance in 2008 guidance.

This graphic is consistent with what Chuck shared with you earlier.

It's what we told you last year versus what our new CapEx projection is.

The top of the bars do not include about $18 million that's spent in our corporate shares and service area.

But all in all, we are preparing to finance a $1.2 billion program in '07.

So the going forward story here is we typically show you five years forward of CapEx.

Here, we have layered on a new 2011.

But that going forward CapEx is up about $600 million.

We told you $4.3 billion was our story last year; it's about $4.9 billion this year.

And since 2011 and 2006 are roughly the same, all the activity is really happening in '07, 2008 and '09.

So it's really kind of right in front of us.

'07 is up about $300 million, '08 about $200 million, and 2009 is up about $100 million.

So that is what's really driving this growth more than we have seen in the past; that is what's driving this 10% to 14%.

And in fact, that is what's driving, in fact, the shape of this earnings growth curve.

So you know from your analysis and we know from looking at your analysis that this is not sort of an 8% to 10% or 10% to 14% growth in a linear fashion.

We think that there's a good amount that's in 2007 and 2008.

But this is the story.

Lee will go through some of the details.

A lot of it driven by Transmission.

Some new projects, some costs that have been escalated, some amount of CapEx that we've moved from '09 to put us in a position to get some of our projects in service earlier, [all from] distribution capital.

A little more distribution capital for CL&P, a little bit more PSNH generation capital as well.

In many respects, this is a slide that I think you have been working off now for about a year, and this is the update.

And this is what supports our view that we can grow this Company 10% to 14%.

We have a total CAGR here of about 12% going forward.

It's about twice that for the Transmission business; it's about half that for the Distribution business.

But nevertheless, as you see on the bottom of this chart, just Transmission, we will go from a year-end rate base in 2006 of about $1.072 billion to $1.776 billion into 2007, a 66% increase.

When we go into 2008, another 30% to 35%.

So that is what is fueling the growth in this overall story.

At the top of this chart, we show you how we have capitalized these companies or how you should think about it.

We haven't changed our views on the underlying capitalization at the utilities, in that 45 to 55.

And that will vary depending on where we are in the rate cycle and where we are in the year.

But I think that is a good way to model.

For the parent, we told you we put on a little more leverage, and that has a lot to do with where we are on the business position profile -- I'll touch on that in a moment.

We've inserted and updated now ROEs going forward in that 11.4 to 12.4 range.

Existing assets, 11.4, new assets 12.4.

And that is a little bit of an uplift to the math that we showed you in the past, and it's one of the reasons -- just one of the reasons -- why we've increase this overall CAGR from 8% to 10% and to 14%.

PUC authorized returns, we think we are in an environment where 9% to 10% is still viable for us.

How do we refinance this?

How do we get this thing done?

For 2007, I think it's a more comfortable answer.

Clearly we have $1 billion of cash now sitting in the system that we will use to fund.

We also expect to issue long-term debt next year at all of our utilities, mostly at the Connecticut Light & Power Company.

The Connecticut Light & Power Company, at least in my view today, will fund all of its assets.

Whether it's C or D, those will come out of CL&P.

And that is roughly, I think, about $500 million, $550 million of the total long-term debt.

And that will keep us in our overall capitalization targets.

Cash from operations, we're looking at about $500 million to $600 million.

We will use it to fund the $1.2 billion CapEx; we will also use it to pay some taxes.

So you know out of that asset sale, the $1 billion of cash we're holding today, half of that is going to go to pay taxes in the March timeframe.

We will earn interest income between now and then; we're booking that at about 5.25 in terms of where we have our money invested.

But expect that we will have that large cash outflow in March.

We also anticipate a short-term debt reduction in the $300 million to $400 million range.

And looking at dividends and our view around dividends, on 154 million shares, that is another $125 million we need to finance.

Longer-term, how do we get this done?

We're looking at, on average, about $500 million in internally generated funds, so that is $2.5 billion contributing to what will be a $5.5 billion of cash needs that we have, by way of CapEx and dividends, both common and preferred. $3 billion in new issuance and cash from the generated sale.

What does new issuance mean?

At the bottom of this page, I say I think that we can meet these cash needs almost exclusively from internal sources and debt financings.

In the past, we've talked about our need for common equity.

When we were here last year, we signaled that we would need some additional common equity in 2008.

Once we found the results from the asset sale, we said -- we signaled to you this summer and this fall that probably we don't see issuance in 2008.

Let me confirm, even with a larger capital program, there will be no issuance in 2007.

I see no issuance in 2008.

But now we're getting out a little bit into the forecast horizon.

And depending on where we are with our business risk position, and Chuck mentioned it, we actually had that position improved by S&P at the close of the after-sale from a 5 to a 4.

If we're in that 3 range, which really looks like a pure play T&D company, and could put a little bit more leverage on the Company still being responsive to our credit rating goal, I'm not sure in this forecast horizon we will need to issue on (indiscernible).

If we stay in the high 50s, probably in 2009, there could be a need.

I think it's a very modest need.

But it depends on where we are with the overall risk position of the Company; it depends on how we're executing going forward.

Either way from a conservative standpoint, maybe 2009 some modest need.

Maybe we can finance our way through that without equity. 2009 is a little bit out there in terms of just duration.

Let me just emphasize one more point, because as I said, we are going to raise debt next year which may be a little counterintuitive given our cash position.

But that is the way we finance our utilities, and I think it's a responsible way to finance these utilities.

And I'd say right now, we're actually a little short leverage.

And this graph demonstrates that we are about 47.9% in debt.

This slice that you see here, the 5.2 million around NGC, that is gone, because we took that out at the close last week.

And when we book a $300 million gain for the sale of that asset in the fourth quarter, not only do we get the cash -- not only do we get the earnings, but it falls right into the equity base of the Company too.

So I think we actually end up the year consolidated at less than 55%.

So we have some leverage capability as we work into 2007, 2008 and beyond.

We are comfortably within our targets, and I think we can comfortably -- although the plan is ambitious, I think we can comfortably finance that plan while being responsive and responsible about the credit quality of the Company.

I'm going to stop there and I'm going to turn the presentation over to Cheryl Grise.

Good morning, everyone.

As I look around, it is so nice to see so many familiar faces who have continued to follow this NU story.

I hope that you like the story that you are hearing today; it is certainly one that we are proud of.

As David and Chuck have discussed this morning, our financial results have improved this year, primarily due to the PLR settlement.

But otherwise, we have seen some slippage due to a combination of lower sales, some due to the weather and some due to the higher commodity prices.

And some are due to higher O&M expenses that we have experienced because of a lot of weather-related outages.

Those of you that live in Fairfield County, I'm sure you know what I'm talking about.

My presentation this morning is going to focus on the challenges as well as the opportunities that our Distribution businesses see ahead.

And I'll talk a bit about how we will address those challenges.

On this slide, I've listed four key factors that will affect our ability to earn a fair return on the rate base that David projected.

That rate base will represent more than 60% of NU's consolidated rate base, and that is even as late as the year 2011.

I will go through each of these four factors in the following slides.

But before we get started, I think it's important for you to note that in all three states where we do business, our regulatory relationships are really quite good.

We have been able to work in Massachusetts this year to settle a rate case.

We are working in New Hampshire, hopefully, towards a settlement there.

And I believe that in Connecticut, although that environment is often considered to be the most contentious of the three states, I believe that we will be able to have good regulatory results as well.

I'll start with CL&P, which represents just over half of the distribution rate base and will continue to do so for the forecasted period.

When I think of what the Distribution businesses at NU have to accomplish in the next two years, I think the most important thing we have to do is to improve the financial results of CL&P.

Trailing 12 month ROE for CL&P is below 7%, and we expect it to be in the low 6%, mid 6% range in 2007 on a regulatory cost of capital basis.

Our authorized ROE is 9.85%.

Earlier this year, we committed to not filing the rate case until mid 2007.

The new rates won't go into effect until the beginning of 2008, when our current four-year plan expires.

Underperformance at CL&P has been due to a number of factors, including the stagnant lower sales that Dave talked about earlier, and most recently, the higher O&M costs associated with an extraordinary number of weather events in Connecticut this year.

Next year's rate case will be critical to restoring adequate returns to CL&P.

We believe our regulators will be reasonably receptive to our increase.

And I don't want you to believe that Connecticut is an environment where 6% to 7% returns are considered acceptable by our regulators or, for that matter, by our management team.

Our current forecast calls for a significant increase in capital spending at CL&P in 2007, $270 million to be exact, and similar amounts will be spent afterwards to address issues relating to equipment aging and peak loads rising.

The average age of CL&P's distribution system is now 35 years, and over 40% of that system is over 40 years old.

That percentage is rising by 2.5% per year.

Making matters worse, older equipment is particularly present in slow-growing urban and rural areas, not so much in newer suburban areas, where we are also required to invest.

I thought you'd be interested to see this slide.

This shows that our peak load -- if you look at the yellow line here -- our peak load is growing much faster than the blue line, which is annual consumption.

And what that means for us is that we're going to have to continue to invest to meet those peak loads, while at the same time we see a flattening of our sales.

This may mean that building forward, we will have to think about alternative rate designs to be sure that we recover the costs associated with necessary higher capital investments.

For example, in Massachusetts, we filed for a partial tracker of our capital costs, and we have secured an agreement to that in the settlement that we've reached.

And if you think about Transmission, those rates are already disconnected from sales volumes.

Moving to Massachusetts, this Company hasn't had a fully litigated rate change in over 15 years, and this year, we were able to settle issues with the Attorney General and other parties.

If that settlement is approved by the Massachusetts DPE, we would have $1 million distribution rate increase in January of 2007 and a $3 million rate increase in 2008.

There would be other trackers that would help us recover certain CapEx uncollectibles and retirement costs.

Overall, the Attorney General has said publicly that the increases next year would be worth about $12 million, and we think that is probably in the general ball park.

WMECO already has a transmission tracker in place and fully recovers all of its power costs.

Over the past 12 months, WMECO's regulatory cost of capital ROE was about 10%, and we think it will stay in that range if the DPUC adopts our settlement proposal.

The parties have asked for a decision on that by December 14th of this year.

PSNH filed for a rate increase in late May of this share and reached a settlement on temporary rates which went into effect in July.

PSNH is earning a regulatory ROE now of about 7%.

Like WMECO, PSNH has had a lot of past success in settling regulatory matters, and we hope to be able to do that again later this year.

If that case doesn't settle, however, hearings would begin in March, with a decision sometime later in the second quarter.

The final decision, whenever it comes, will be retroactive to July 1st of this year.

Unlike CL&P and Western Massachusetts, I could remind you that PSNH does not have a transmission tracking mechanism, which hurts us when transmission costs are rising, as they are today.

We are seeking a tracker in the current case to deal with this issue.

It's also worth noting, before we leave this slide, that PSNH also faces some of the same distribution reliability issues that I described for CL&P, and our projected distribution capital program is up quite a bit from last year's forecast that I discussed with you.

Recovering the reliability-related costs will be one of the key things we'll need to address in PSNH's rate (technical difficulty).

One advantage you'll see here that we have is New Hampshire is that rates have fallen significantly in the last year.

As a result of our fully-stranded cost of recovery -- full-stranded cost of recovery in mid year 2006 and our relatively low energy prices, largely driven by our own generation, our rates were actually cut by 15.5% in July, despite a $24.5 million distribution rate increase that went into effect at the same time.

PSNH generates about 75% of the power that it delivers to its customers in New Hampshire, and its rates are now, I'm happy to say. the lowest in New England.

And there are reasons that they could decline even further in the coming years, as two high IPP rate orders expire in 2007 and 2008, and some rate reduction volumes are fully amortized in 2008.

Bottom-line, this gives us a lot of head room in New Hampshire going forward.

Yankee Gas, our Connecticut gas company here, will file its notice of intent to file a rate case about a month from now.

There will be two major parts to that rate case.

The first is to reflect in rates the capital costs associated with a new LNG facility.

Most, if not all, of those capital costs will be offset by lower commodity and pipeline capacity contracts.

The second part of the case will be to address the need to improve Yankee's returns, which are now about 7% on a trailing 12-month basis.

And like the electric company, Yankee's CapEx will actually decline significantly once the LNG facility is complete and in rate.

The rate base growth after 2007 should be very modest at Yankee -- only about 7% (technical difficulty).

Here you see photographs of two of our capital projects that Chuck mentioned earlier.

Construction of the LNG facility, shown on the left, has gone well and it is now about 85% complete.

We expect to begin filling that tank next spring and have it in operation for the 2007/ 2008 heating season.

It will help meet a significant need for natural gas storage in Connecticut, and I'm pleased to report that that project is both on schedule and on budget.

The chart on the right shows PSNH's wood chip biomass plant.

I know some of you were up to visit that plant last year with us.

In New Hampshire, we have an allowed 9.62% ROE for all generation.

The plant also will benefit from about $3 million in federal production tax credits and from selling renewable energy credits, particularly in the state of Massachusetts.

It also will help PSNH's entire generation fleet to meet emission requirements (technical difficulty).

Chuck mentioned earlier that there may be some future generation opportunities for us on the horizon.

I do want to remind you, though, that there is only one significant new generation investment reflected in our forecast, and that is at PSNH, where we will install server technology at two units where we have a large baseload stationed in (indiscernible) New Hampshire.

The cost will be about $250 million, and it will be recoverable through rates.

In fact, earlier this year, the New Hampshire Legislature specifically approved a bill allowing for this work and for the costs to rate-based.

There were two other generation initiatives in 2006, one in Connecticut and one in New Hampshire.

They would have provided our Company with the ability to build generation.

In New Hampshire, we were focusing primarily on biomass generation, and in Connecticut, primarily on peaking generation.

Neither of those bills passed in 2006, but we fully expect that both may be resurrected in the next session of the Legislature.

But what I want to point out is there is nothing that is forecast other than the scrubber technology in New Hampshire.

What that, I'd like to thank you for your time and I'll turn the podium over to Leon Olivier.

Thank you.

Thank you and good morning, it's great to be here.

I see a lot of familiar faces from our recent transmission investment conference in Delaware, so some of this will sound familiar to you.

Dave and Chuck talked about the overall NU growth strategy and how transmission really ties into that growth strategy.

What I'd like to do is to give you an overview of that strategy today, give you some more specifics.

I want to give you a high-level look at the transmission business.

Chuck kind of touched on that a little bit.

Talk about our performance year-to-date -- overall the transmission performance both from the standpoint of operational excellence and execution of our capital program has been very, very strong.

I'll give you the status of our Southwest Connecticut projects, our major projects, but overall I think you heard Chuck say that they are doing extremely well.

And I'm going to cover some of the other projects that we have spread throughout the three state region.

We talk a lot about Southwest Connecticut but we're actually building a lot of other smaller projects in New Hampshire, in Massachusetts and, as we go forward, more of those projects will be in those areas.

I'll talk about our CapEx plan, and clearly it remains very robust for the five-year coming period.

Notwithstanding the fact that projects like the Bethel-to-Norwalk project rolloff.

It looks very good.

We'll cover a big part of that back end which is this series of projects called the SNETR projects or, for those of you that suffer with this acronym as I do, it's the Southern New England Electric Transmission Reinforcement project -- that's actually a family of projects that we refer to as SNETR.

And then we'll talk a little bit about future opportunities.

Just the highlights of the overall NU transmission business.

As Chuck said, the NU transmission business is the largest transmission business inside of New England.

We serve about 2.4 million customers, both our own as well as a number of other smaller utilities and municipals.

Clearly the biggest part of that is Connecticut Light & Power and you can see by the number of circuit miles and rate base it is the biggest piece, it no doubt will remain the biggest piece as we go forward.

But you will see more investment again in Massachusetts and SNETR -- Massachusetts and New Hampshire as we go forward.

You can see from that bottom bullet there we're adding about 140 new miles of new transmission.

For any of you that have heard Chairman Kelliher of the Federal Energy Regulatory Commission speak.

He always talks about investing 3 to $4 billion of investment in transmission on a yearly basis, but very few new miles.

That 140 miles does not reflect the new miles that will come with SNETR; most of these miles are all in the Southwest Connecticut region in central part of Connecticut.

So in all likelihood SNETR will probably add another 100 or more miles of new transmission projects.

Most notably we started the year at $605 million of rate base.

We're going to end the year with almost $1.1 billion and over the five-year period almost $3 billion.

So A very aggressive buildout of transmission.

Let's take a quick look in terms of our overall performance year-to-date.

Clearly the first thing that we have to focus on is operational excellence, it's making sure that we operate our systems safely, reliably and in a way that is environmentally sound.

If you don't do that you probably don't get to build out new transmission and overall this year has been a very, very strong year for us.

In terms of our reliability, in the peak summer periods we set several new peaks;

New England went over 28,000 megawatts, almost 28,500 when you consider they had about 500 megawatts of demand reduction during that period of time.

Our system held up extremely well.

We've had no outages, very strong performance of the system.

Some areas such as Southwest Connecticut and up around Springfield, Massachusetts were very tight, but it was very strong.

We've had outstanding performance in terms of safety.

We've had no issue reportable for lost time accidents, no environmental violations.

Our contract is really operated from the top decile in terms of safety performance.

So the overall execution -- it's not only getting it done, it's getting it done with real high levels of quality.

And as you can see there, the bullet above it is we had about a 14% increase in peak demand load from the period of 2003 to 2006 in the peaks that we had this year where actually the ISO-New England projected peaks in 2009.

So what we found is the ISO-New England projections going forward into 2014 and '15 are actually very conservative.

So the demand is growing actually ahead of ISO's projection.

All of our capital projects are on schedule, they're on budget.

Year-to-date we'll spend all of our $454 million of capital, which is the largest capital program we have ever had, in transmission.

The good news clearly is the Bethel-to-Norwalk project and, of course, for those that attended the conference in Norwalk the day after the conference the line went and service.

And as Chuck said, we you go there you don't want to see sparks flying.

It actually went into service very cleanly and very reliable year-to-date and we're carrying about a couple hundred megawatts of load.

That project, as we've told you before, will probably eliminate about $100 million of federally mandated congestion cost to customers in Southwest Connecticut.

If the project adds about $0.69 a month to the average 700 kW customer bill it actually eliminates about $2.15 of congestion.

So it will really pay for itself as many of these other projects do, even though they're fundamentally all reliability-based projects.

And from the last bullet we'll see with the mandatory reliability standards coming into effect July of next year, the risk for a while of anybody's transmission business is changing.

Anytime that the regulator, in this case FERC, can implement a $1 million civil penalty a day your risk profile has changed.

And that's not from the time that they discover the violation, it's from the time that the violation occurred.

So if it occurred 200 days before that it would cost you a lot of money.

We will be ready for those reliability standards.

We have been a leader in this area back when (indiscernible) was voluntary and the leader in the Northeast power coordinated counsel in terms of running our business had a very, very high standard.

Now we recently received our FERC return on equity case and I'm going to cover that.

And for those of you that don't want to write a lot of notes I have a handout which will say essentially everything and I'm going to tell you because it's somewhat complex.

But before I do that, just as a refresher, all of our rates are FERC deregulated.

They're a (indiscernible).

They are fully tracking.

They're prospective.

When we forecast in May and November and we do monthly and really (indiscernible) we pretty much eliminate the lags.

And as Cheryl has indicated, we've got trackers both in Massachusetts and Connecticut and hopefully next year one in New Hampshire.

We look at the overall rate decision as one that really is building out new transmissions -- very, very clear not so much maintaining older existing transmissions, but gets us building out new transmission.

From that standpoint we think that FERC has got it done right.

We do think it will cause some new transmission to be incented and built.

I'm going to run through the order.

First of all, the order contained a 10.2% base return on equity effective February 1, of 2005.

The February 1st thing was previously agreed-upon by the New England transmission owners, it coincides with the start of the RTO in New England.

FERC added a 74 basis point true-up for 10-year treasuries bringing the going forward base return on equity to 10.94% effective November 1st of this year.

The commission established a 50 basis points for transmission owners joining the RTO effective February 1st.

So for the lock-in period of February 1, 2005 through October 31, 2006 the existing regional cold transmission facilities receives an ROE of 10.7% plus the 50 basis points added to the RTO.

From newer regional transmission facilities that were built during this period, a return on equity of 11.7% is provided.

So that's 10.2, the 50 basis points for joining the RTO, the 100 basis points for new transmissions so it's 11.7.

But new regional transmission facilities effective November 1, 2006 we received 12.44% return, 10.2, the 50 basis points, 100 basis points and the 74 basis point adder for the true up of treasuries.

So at the end of 2006 we believe the blended return on equity will be about 11% and as we told you, we've been booking 11.5% return on equity and collecting that 13.3, so we've got about a $14.1 million reserve that will be returned back to customers.

And Dave covered a little bit of that.

We're actually doing the final calculations, but it won't make a major impact on our performance year-to-date.

Of the existing plant that we have, approximately 75% of that plant is regional or coal transmission facilities, of course 25% would be localized.

So on a going-forward basis, our transmission capital program is largely comprised of regional infrastructure that is included within the regional planning process.

Over 90% of our projected $2.4 billion 2007 to 2011 capital program is expected to be in this category and therefore will earn 12.44%.

Now this new plan is added to service during this forecast period and the old plant is depreciated.

Our percentage of new plant becomes a larger portion of the net plant grown from about 57% at the end of this year, 65% in 2007, and over the course of this period of time about 85% by the end of the period.

So the changing mix of associative ROEs produces about 11.9% blended ROE in 2007 and about a 12.2% over the forecast period of time.

Needless to say this is in all likelihood going to be -- they'll be challenges and we'll have interveners.

We believe that the language, the way this order is written will hold up to any legal challenges and so therefore we're in the process of working with the other regional transmission operators to put together our compliance filing and look at any aspects that we may want to file for (inaudible).

Now a real quick look at our Southwest Connecticut projects.

Normally I would spend more detail but I think the story here is pretty much as Chuck said.

All of these projects are cited; they're all under construction.

Bethel-to-Norwalk is done, Middletown-to-Norwalk is actually ahead of schedule.

We expect to complete about 12% of that project this year.

The big news here is we have really mitigated the risk associated with these projects because fundamentally all of the projects have contracts that have been issued both to component makers such as transformers/conductors and also with major contractors to actually build it.

So the risk in terms of pricing and timing on this project or these projects are essentially for the most part eliminated.

These projects again will solve the reliability areas of Southwest Connecticut at least for the next 20 to 25 years.

They will enable existing power plants in that area to repower so they will now be able to connect on to the 245 kd grid.

So all in all it will be very strong story.

Just a quick look at what else we're doing in terms of CapEx, in terms of the three states we do business in.

Chuck talked about the fact that 55% of all of the capital inside of the ISO-New England regional system plan, and that's the plan that is expiring now, the new plan is out in draft form.

We have about 55% of that and that was about $3.3 billion.

The new plan has about $3.5 billion in it when you subtract out Bethel-to-Norwalk.

And we have about 59% of all of that transmission capital going forward in this time period.

When you look at projects that we have recently completed, a number of projects throughout the three state region, clearly Bethel-to-Norwalk and the STATCOM down in Stamford added about $430 million of plant and service.

The projects under construction right now -- we have about $1.4 billion actively under construction that we're managing right now.

And again, as I said, it's all on schedule and budget.

We have about $110 million -- that's that whatever it is, gold or orange circle -- that we've recently received ISO-New England technical approval.

So for the most part there you just go with (indiscernible) those particular projects really require minimal siting to get them built.

It's not like building big projects in Southwest Connecticut.

And of course you've got the future projects and a big part of that is the SNETR projects and we'll talk about that in a minute, but also a number of other projects in New Hampshire.

New Hampshire, Southern New Hampshire particularly has seen a significant growth as a result of the overflow from the Boston area and they need a significant amount of transmission.

They have very little 345 kV transmission in that area so there will be a lot more built as we go forward.

Now here is our CapEx program going forward for the next five-year period.

As you can see, it continues to be very robust and it is being primarily driven by the New England regional system plan.

And notwithstanding the fact that we rolled out the Bethel-to-Norwalk project; we're looking at about a $2.4 billion spend during that period of time.

CapEx has grown by a factor of 27 since 2001, a major increase.

It breaks down to three major buckets.

The first one is the green and that's about $1.1 billion to finish off the projects inside of Southwest Connecticut.

The gold is the SNETR projects.

Now the old forecast we had had about $400 million, so we've added about $310 million to that.

And I can tell you quite frankly here this morning that's a minimum.

That's a minimum of what that project will cost.

Those are a series of projects that could be well over $1 billion to $1.5 billion.

Of course the remaining piece is that blue which is about $650 million of projects that are smaller in nature but are spread across a three-state region, many of which need minimal siting, a lot of them are what we call inside the fence, you just go ahead and do it with a permit.

And so our confidence level in those projects as well as the rest of this capital spend is very, very high.

Let's take a look at our SNETR project.

And SNETR really solves a number of things.

And for those of you that have read the Department of Energy congestion report that recently came out, it looks that that area as one of the areas of significant concern in the nation in terms of transmission, transferability and reliability.

And SNETR is really designed to solve four things.

One is Connecticut from an electrical standpoint, transmission is isolated for the most part away from the rest of the region.

I'll give you an example.

In Connecticut the average price of allocational marginal pricing average megawatt hour is about $8 to $9 higher than the rest of the region, adding up to some $330 million a year, the excess cost that Connecticut customers have to pay.

During the peak demand periods of time the current goes to where the load is.

It wants to go down to Southwest Connecticut and in the process it overloads all of those lines trying to get there.

The first thing that has to happen with SNETR is we have to open up Connecticut to the rest of the region by adding transmission in from either Rhode Island or Massachusetts or both.

And so you have more transfer coming in.

Connecticut is also shorter generation.

Right now it's short about 279 MW, by 2014 it's projected to be about 1000.

When you look at -- once you get power inside the state you've got to get it to Southwest Connecticut so there will be more expansion of lines there.

The third thing is in and around the area of Springfield, Massachusetts, those lines are as well overloaded and they need to be upgraded and finally the ties between Eastern and Western Massachusetts.

So again, we're looking at a project that could go well over $1 billion.

Where are we today?

We should have the final routing at SNETR chosen by the end of this year.

We will then give that to ISO-New England, they will start their technical review process and from that point on we will start deciding process in 2007 so we're on track with that project.

Finally just a look into the future.

Beyond the SNETR project which will range out to the time period of 2012, 2013, there are a number of other issues that have been identified inside of the regional system plan that need to be resolved bottlenecks between Maine and New Hampshire, between New Hampshire and Massachusetts need to be resolved.

The ISO-New England grid which is designed for 30 G or 30,000 MW has essentially used up all of its capacity.

ISO is designing a grid that is going to be 40 to 50 G which means there will be significantly more 2.5 kV transmissions built throughout the region.

And of course there will be a new transmission as a result of aging infrastructure -- no different from a distribution business and as well as we believe as a result of the mandatory reliability standards that are implemented next year.

The final bullet just talks about something that is very interesting.

In looking up New England, New England really has no intrinsic fuel sources other than perhaps biomass which Cheryl has been busy building plans in New Hampshire.

But if you look out into the get pipeline, gas hits the marginal pricing power 86% of the time.

Other parts of the nation such as the West have the solutions through coal, solutions through coal and nuclear.

New England really doesn't have a solution.

There's an initiative that's been put in place by ISO-New England and supported by a number of state governments to look up running transmission lines up to Canada, up either through New Hampshire, our service territory, or Vermont into Quebec also down through maritime purposes into New England.

In Canada they are winter peaking, we are summer peaking.

They have excess power in the summertime.

So there's just a lot of natural synergies.

ISO-New England expect to have a recommendation about midyear next year and we are working with them looking at the viability of that.

We think there is significant additional opportunities to build through transmission as you go forward.

That's it, Chuck, and I think I'm turning it back to you.

Thank you, Lee.

Cheryl, David thank you very much.

And thank all of you for joining us today.

We'll have some time for some Q&A when we finish this.

This was designed to be a summary.

I think we've pretty much hit most of these points.

We announced a strategic transformation in this company a year ago, I think we are very much on track to accomplish that.

Clearly the results have been at least as well as we expected and I think we've seen from today's discussion that we see the results going out the next five years to even be better.

Our financial flexibility is significantly improved not only because of the business risk profile change but also because, as David said, we now have $1 billion in at the bank.

I think you've seen from Lee that the transmission business is growing.

Over the five-year period what we know grows and there may be other opportunities that are not in these models and we will keep you apprised of this.

Distribution results are expected to improve.

We do have a series of distribution rate cases.

We are literally in a distribution rate case -- either concluding one or are in one in every one of our jurisdictions in 2007.

And they are going to be the successful resolution that is going to be critical I think for this company's success in that line of business as we go forward.

And I think NU has in fact begun to take the leadership role in meeting New England's energy challenges and whether that's building additional transmission reliability investments in distribution, New Generation or a lot of the new energy efficiency technologies it is clearly our home.

We can't pick these companies up and move them.

We need to do everything we can to make sure that our customers get the service that they need. (indiscernible) stop and just open it up to questions and answers.

And David, if you and Cheryl need to join Jeff and I up here.

I'm going to repeat the question for those on the Web cast, Mary.

(inaudible question - microphone inaccessible)

The question is what comprises the increase in CapEx in '07?

In '08.

I think you've got it directionally correct, and not only for inside the projects that you turned in, but as Cheryl suggested, some meaningful increases in distribution capital, both in New Hampshire and in Connecticut, also some increases in (indiscernible) generation which you know is fully tracking with its own sort of rate base.

So that's driving some growth.

And as well, some - just a recovery in the overall returns that these companies are earning, particularly as we go into 2008.

In fact, that's probably one of the most significant drivers in 2008 -- looking at the average common equity of these companies, what they're earning in 2007 and then driven by a (indiscernible) rate case as well as new revenues from the jurisdictions.

How do we improve that overall ROE across all of our distribution rate base?

That's a big driver as well as the transmission (inaudible).

(inaudible question - microphone inaccessible)

Same thing.

Same thing.

(inaudible question - microphone inaccessible)

The question is what are our assumptions for distribution ROE in the various jurisdictions?

For transmission we laid that out I think pretty clearly.

The existing asset base (indiscernible) assets at 12.4.

With the distribution companies we've got a graphic here that generally talks about expecting authorized returns in the neighborhood of 9, 10%.

I wouldn't say they're lofty expectations, but it's certainly our objective then to not only receive these authorized returns but to earn them out.

We think right now for Western Mass we have a settlement that puts us squarely into that position.

We think as we work through the (indiscernible) rate case that should put us in that position.

Yankee Gas is still not quite in the hopper yet, but I think for CL&P our view is that there's no reason for that company not earning in that range as well.

And when we file testimony and build a case around ROE and exit the hearing room and exit the rate case I think that's a reasonable expectation for us to have relative to the 7% that they're earning today.

(inaudible question - microphone inaccessible)

The question is when we talk about a 10 to 14% EPS CAGR what are the assumptions about total rates or just the distribution and the transmission rates?

Just the distribution transmission rate.

Okay, for each of the jurisdictions I think you're asking.

(inaudible question - microphone inaccessible)

Okay.

Systemwide we now have, as you can see on one of the charts, a distribution rate somewhere in the $0.025 to $0.03 transmission rate or in the 0.5 or 0.7 [cents], what's the assumption as to what happens to those over time?

On transmission, just if you look at Connecticut where it's about $0.76 per kilowatt-hour this year, over the buildout, this buildout period, you can go to about $0.011 per kilowatt-hour.

And then if you look at the offsets against that in terms of saving of congestion costs it actually theoretically you'd be down by somewhere back around 0.5, back down around 5 [mills] as a result of eliminating congestion costs and equilibrium costs in terms of location marginal pricing with the rest of New England.

And if you looked at the other two states, Massachusetts and New Hampshire, it would actually be more profound in New Hampshire just by the fact that we're putting in place now upgrades to substations that eliminate RMR contracts to some of the generators up there so it's more profound in New Hampshire and Massachusetts is the smaller of the two.

(inaudible question - microphone inaccessible)

We would do these upgrades and then the customers will get the benefits of those savings.

And of course that creates some headroom for the distribution [regs] as well.

(inaudible question - microphone inaccessible)

The actual charge per transmission goes from 0.72 to 1.1.

So you would see that on your customer's bill, you just offset other costs.

I think if you look at that in the slide that you have in front of you for CL&P, there's a brown box at the top that shows FMCC other costs.

You'll see that box get smaller.

As we see transmission over time get a little greater we'll see some of these other federally mandated cost congestions and others go down.

So as to I think your question is on the distribution side of the business what kinds of increases are we expecting for this next round of (indiscernible).

That's a hard thing to --.

(inaudible question - microphone inaccessible)

I don't think that I can project for you what our rate increases will be over the next five years.

(inaudible question - microphone inaccessible)

It's a fairly modest level of increases we are assuming.

On average the rate cases that are going into place now probably another take coming on.

But we are assuming that we will have rates that will allow us to earn in the 9 to 10% range that David has talked about.

So if that's required, as circumstances require we would have to go in every year for a rate case, that's foreseeable.

But we are assuming that we earn returns in the 9 to 10% range throughout this period on average for the four distribution utilities.

I don't know if that is sufficient to answer your question.

(inaudible question - microphone inaccessible)

I cannot tell you that throughout the entire period.

What I can tell you is that the settlement that we've reached in New Hampshire, if that settlement is approved by the Massachusetts [GTE] we would see customers' rates on the delivery component go up by about 2%, that's not very substantial.

And our projection is that all the moving parts in the Yankee case was putting in, the LNG facilities as well as trying to move their ROE up to a more competitive level, rates will still increase in the single digit kind of range.

We don't see double-digit increases for the distribution component of that rate case.

It's too early, I think, to project where rates are going to go in Connecticut at this time.

We won't file that case for another eight months from now.

And at (indiscernible) probably still the single digits kind of range for the first increase.

But beyond that I can't tell you because there are too many other variables that can come in over that five-year period.

We will plan to earn 9 to 10%.

Let me take one more question and then we'll stay around here as long as you guys have questions.

(inaudible question - microphone inaccessible)

The question is if you're taking a look at our five-year capital program for transmission, some of it's been approved, some of it hasn't.

How much of it's been approved by the siting board and so forth?

If you look at obviously the Southwest Connecticut projects, $1.1 billion there remains to be spent, all of that's sited.

If you look at the $710 million of SNETR, none of that is sited.

If you look at the $650 million of what's left, we have about a couple hundred million dollars of that that is sited.

The remainder for the most part are things that you do to essentially permit.

Very little siting is needed on the rest of it.

So we think from a siting standpoint, barring the SNETR projects, we're in pretty good shape.

Well, I just want to thank you all for joining us this morning and bearing with us in the beginning where we had arranged our webcast.

We'll stay around for a while.

Again, we're over in the (indiscernible) Sienna room.

And (indiscernible) also if you want, we'll have a handout both here, that's on the transmission ROE decision, and we'll also have them in the Sienna room this afternoon for our breakout.

So thank you very much.