康涅狄格電力 (ES) 2004 Q3 法說會逐字稿

Thank you for joining us today. My name is Jeff Kotkin, and I am NU's vice president of Investor Relations. And I know it is fairly early in the mornings so we appreciate everybody getting up and coming over. We appreciate it.

Before we get started I am just going to read and our Safe Harbor provision. And it is a little denser than it used to be, but if you bear with me. We are webcasting this so we need to make sure that the folks who are up on the webcast hear this as well. This presentation includes statements concerning the Company's expectations, plans, objectives, future financial performance and other statements that are not historical fact. These statements are forward-looking statements within the meaning of the Private Litigation Reform Act of 1995.

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. They include but are not limited to actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, expiration or initiation of significant energy supply contracts, regulation or regulatory policy, levels of capital expenditures, development and legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors.

Other risk factors are detailed from time to time in our reports to the SEC. And we undertake the obligation to update the information contained in any forward-looking statements to reflects developments or circumstances occurring after the statement is made.

Thank you very much for joining us. I assure you that will be the last thing that is read today. So let me with that introduce NU's Chairman, President and CEO, Chuck Shivery.

Good morning. Thank you very much for joining us. Jeff, thank you for the reading of that statement, that was really great.

Before we get started in today's presentation there are just a couple of things that I would like to mention to everybody. We have put a couple of press releases out over the last few weeks. And one of those indicating that our Executive Vice President, Vice Chairman of the Board, and Chief Financial Officer, John Forsgren, would be retiring at the end of this year. John has decided he is going to sit in the back and just relax and watch this today.

But I will tell you that -- and you will see this in the presentation, this Company is in great shape going forward. Not only from a strategic standpoint but from a financial standpoint. That was not the case when John first joined Northeast Utilities. And we owe him an awful lot of credit. And again I have done this before, but I would publicly like to thank John for everything that he has done for this Company.

As a result of John's decision, we elected Dave McHale to be the Chief Financial Officer effective January 1. Dave was the Treasurer of the Company, and I'm sure most of you know him. In addition to that change, Randy Shoops who was the Assistant Treasurer was elected Treasurer on January 1. And Randy is here -- somewhere over there --. In addition to Randy, we have John Stack with us. John is the Corporate Controller of the organization. And then the other folks, Cheryl Grisé, who runs the Utility Group and Dave Boguslawski, who runs our Transmission Group, you'll hear from as we go through the program.

The other announcement that we made was that Larry DeSimone who was until recently an Executive Vice President of PPL and ran both their regulated and unregulated parts of their business would be joining NU to run all of the Competitive businesses. Larry is actually starting today at Connecticut. He is going through paperwork and processing and physicals, and all those kind of things. And we are very, very happy to have Larry with us running the Competitive businesses.

There is one other piece of news that just happened on Friday, and let you know that before we get into the presentation. As you know, the litigation with ConEd has been an ongoing thing for a long time. And there was a decision made, we call the Ridcosky (ph) decision. And it really was a decision around which shareholders would benefit should there be any benefit from the ConEd litigation. And Judge Kodel (ph) had decided in his decision that the shareholders that were shareholders as of March of 2001, when the merger broke up, would be the ones to receive value, if there were value. We have always felt that it should be current shareholders. But we appealed that to the Second Circuit, and on Friday the Second Circuit issued a statement saying that they would hear that appeal.

We don't know a lot more details than that. We haven't picked up the order yet, so we don't know the timing of anything. But they did issue that order on Friday. They also issued an order on Friday saying they would hear the appeal of ConEd around our ability to bring the lawsuit. And that was a decision that was made by Judge Kodel in our favor back 18 months, two years ago. So that there are two pieces of that appeal that apparently are going to be heard by the Second Circuit. We do not know any more of the details than that. We are going to pick up the order today, and then we will be advising you if there is anything else. But I did want to let everybody know that because one of the questions that we typically get in is what is the status of the ConEd litigation.

We really want to do a couple of things today. We would like to spend a little time with you. And then hopefully you have already seen the earnings news release for the third quarter. But we want to spend a little time with you going over 2004, where we ended up for the first nine months. What the rest of the year looks like, and some of the other things that we have accomplished in 2004. And David McHale will spend a little bit more time giving you a little more details about how the third quarter turned out and what we expect for the year.

I would like to spend just a little time talking about the enterprise planning process that we went through. There's nothing of significant changes. As you'll see -- I actually think that is a good thing. Because what we have been able to do is on a business by business basis is essentially validate the strategy that we think is a very good strategy to start with.

And then we will move into '05. We will provide some various guidance for '05, talk a little bit about the earnings drivers and the (indiscernible) that we have. And Dave will spend some time talking about the quality of the balance sheet, which in fact is one of the things that allows us to go forward with a fairly aggressive strategic plan over the next five years.

And then you'll hear in more detail from Dave McHale about the Competitive businesses, but from Cheryl about the Regulated Distribution businesses, and from Dave about the Transmission business. So that is what we would like to accomplish in the next hour or so, and have some time for questions with you.

As you know by news -- from the news release we earned 30 cents in the third quarter compared to about 31 cents in the third quarter last year. Year-to-date we're up a little bit, 1.01 versus 99 cents for last year. And we have narrowed earnings guidance for the year 2004 to $1.25 to $1.35. That range was originally $1.20 to $1.40. So we have tightened that a little bit. And Dave will spend a little more time going into the details around that.

For the third quarter, or for the first nine months, you can see it is really driven by three things. CL&P is up about $6 million. Yankee Gas is up about $5 million, and the Competitive businesses are up about 5 million. PSNH is up a little bit. WMECO IS down. We will spend a little time dealing with that. The returns, they are not what we think are appropriate. And the one really disappointing thing this year has been the services business. And although it is not a lot of money, the differential between this year and last year was in fact close to $3 million. And we will attempt to talk a little bit about what we expect to do with these businesses going forward.

If you step back and look at what we really accomplished in 2004, multiple regulatory uncertainties have been resolved. The profitability of the Merchant Energy business has been extended to include the SMB write-off from last year. It is essentially 7 quarters in a row of profitability from the competitive businesses.

Overall earnings are on track for 2004. We have maintained a strong financial position, and the strategy has been validated. We're talking a little bit about this at the table before I came up here. And if you look back a year ago, and look at the uncertainty that faced this organizations and look at where we are right now, on the distribution and the regulated generation side the CL&P rate case was resolved in December. We also have now resolved the request for reconsideration around that decision in a way that was favorable to us. The PSNH rate date is completed. The Yankee Gas rate case, the settlement is pending. The Consumers Council, the prosecutorial unit of the DPUC and ourselves have all agreed. So the decision in front of the DPUC now to get that resolved.

The public service -- the Public Service of New Hampshire Northern Wood Project, which is about a $75 million conversion of the 50 megawatt coal-fired boiler to a wood chip boiler is essentially approved and going forward. And the Connecticut DPUC approved the Yankee Gas request to build the LNG facility, which is slightly over $100 million over the next couple of years.

On the transmission side, the FERC rate case is done. That went back to October of 2003. But that has been completed. The appeal on Bethel and Norwalk is completed in our favor. And agreement to replace what we call the 1385 table between Connecticut and Long Island, that agreement has been put in place, and we will be moving forward to replace that cable over the next two years. And Dave Boguslawski will talk about that when he talks about transmission. And on the competitive businesses the CL&P dispute Around whether the suppliers or Connecticut Life and Power's customers paid has been resolved. So if you step back from where we are right now, and look back a year to where we were a year ago, we have resolved a significant amount of uncertainty in this business going forward.

I talked about the enterprise planning process. Let me -- I have used this slide before, but this is how we look at the business. And this is how we will report the business to you in terms of the earnings potential of the different segments of the business. And it is also how we will report back to you on a quarterly basis how we are doing in each one of those segments.

And on the regulated side there really are two. There's a regulated distribution segment of the business, three electric distribution companies, one gas distribution company, but it also includes regulated generation at the Public Service of New Hampshire, and then that is the transmission business.

On a competitive side, there's a wholesale supply that includes slightly less than 1500 MW of power plants that we own, plus the origination function around standard offer service before refining service with the wholesale side of the business. Retail is in large industrial and commercial customers. And then the services businesses are really generation services, energy services, and there's some electrical contracting business in there.

The interesting thing about all these business is they are again moving forward the way we would them. Retailers, you remember lost $28 million in 2002 that lost slightly less than $2 million in 2003 is profitable in 2004. So it is in fact moving forward very nicely.

We went through this whole strategic planning process. It is bottoms up. We have talked about this before. We took every business and said, tell us what the environment is like that you are in. Tell us what your strengths and weaknesses are. Tell us what you can do if there were not any constraints about it. And how could you in fact improve the value to our shareholders. We did that starting in February of this year. Worked through that with the Board. Had an off-site in July and feedback in September, and finalized that strategic plan.

You'll hear a lot more about that as we go forward, but on the regulated side of the business there are some very unique situations in New England that are both challenges, but they are tremendous opportunities for us. We need to expand the transmission system. Our customers need it, our customers require it. That is part of this plan. We need to upgrade distribution facilities in the service territories in which we operate. Our customers need it. The DPUC, especially in Connecticut, has reapproved a four year plan to do that, and we're moving forward with that. We will increase local natural gas storage because it will benefit our customers as we move forward. And we will reduce power plant emissions, and that is the Northern Wood Project for New Hampshire.

The regulated strategic plan fits with what our customers need. It also benefits our shareholders, clearly increases investment opportunities. We think we will provide above-average earnings growth. We think we can provide above-average dividend growth. And we think we can all do that while maintaining a strong credit profile. And what you'll hear as we work through the rest of this morning is a lot more detail around how we are going to do that in each of the businesses, and how we going to continue to maintain the strong credit profile that gives us the flexibility of doing that as we go forward.

When a lot of you think about the regulated distribution strategy, the investment of significant dollars over the next five years into distribution and transmission rate base. What comes to mind immediately are the very high-profile projects, because you see those. And if you happen to live in the Connecticut area you see those in the newspaper. And there are some very high-profile projects. And here are three of them, (indiscernible) LNG project is about $100 million. It is already been approved. PSNH Northern Wood Project is $75 million. It has already been approved. So that is the (indiscernible) of being able to execute.

The one in the middle, which is the Southwest Connecticut Transmission, is about $1 billion. There are two or three major transmission projects going into Southwest Connecticut. Southwest Connecticut clearly needs that transmission. As we see that load (indiscernible). And there's controversy right now about exactly where we are going to build it and exactly what the structure will be. And some questions around the timing of when that will get built. And based on a fair amount of time going in that in detail so you get a sense around the potential variability of those big projects.

But those are the high-profile projects. What I want to make sure everybody understands is that we started talking about this before, as we are going to spend a lot of capital over the next five years on projects that don't have anywhere near that level of profile, that look a lot like distribution projects. Even though some of them are in fact transmission substations, autotransformers that increased the capacity banks. But they don't get the notoriety. They don't get the controversy. And it really is more a question of execution around those projects. Designing them and building them, and then of course making sure that we have the appropriate rate treatment so that we get paid not only a fair return but a timely return on those projects.

But as you can see over the next five years we are going to spend over $400 million a year on those type projects. One of the things we will do is report back to you as to how those capital programs are going. But they really are programs that are not controversy, and just literally require us to execute it.

On the competitive side of the business, it is moving in the direction we wanted it to. They are about where we expected them to be this year, with the exception of the services businesses. They will provide a source of cash to fund regulated growth. There will be some additional opportunities on both wholesale and retail as markets continue to open up. We're seeing PJM continue to open up on the retail side. There will be some additional opportunities. We expect those businesses to grow modestly, but to be profitable and throw off a significant amount of cash. And we don't see, given as long as the current liquidity situation stays the way it is right now, any need for significant new capital in those businesses during this planning timeframe. And because of the strong risk management skills, we think we've stabilized and will continue to stabilize our financial performance.

So if you step back and you look at this Company right now, you have a Company that has an unique opportunity to invest in needed energy infrastructure, whether that is transmission, distribution or in some cases regulated generation. We have a balance sheet which is capable of sustaining those investments and maintaining a very high credit quality. We have the opportunity we think to grow above the industry average. We can execute around that and grow that way. We have the opportunity to increase the dividend faster than the industry average.

And we think the competitive businesses will continue to produce earnings and free cash that we can then use to reinvest in the business. We're pretty excited about this investment thesis. We're pretty excited about the strategic planning process. What we would like to do now is show you, as we work through the rest of the speakers, a little more detail about how we are going to accomplish this. Thank you very much.

Earlier Chuck shared with you our range for 2004. We narrowed the range from $1.20 to $1.40 as we shared with you earlier in the year. In fact I think introduced last year at this conference where $1.25 to $1.35. In terms of looking at our segments this is how it works out for the year. We're expecting the regulated distribution and generation businesses to earn between 91 and 95 cents a share.

And this is how we look at it segmented, and recall that the transmission in regulated distribution businesses are housed in the illegal entities CL&P, PSNH, etc, but they are reporting here because transmission is a major line of business for us. So the distribution companies which include Yankee were 91 to 95, transmission 22 to 24, and then equally the competitive companies, 23 to 25.

I think you know if you follow us, we do book a lot each year at the parent organization, primarily as a result of deficits carried at the NU parent level, as well as some additional loan and expenses at the NU parent level.

In terms of our earnings profile, both historically then and then going forward you can see that there has been a trend since 2005 where the earnings have actually come down. And there is a trough in 2002. And this represents the cycle that the Company is going to in terms of restructuring and decapitalizing the Company. As we (indiscernible) generating assets and the restructuring process, we move down from rate based, we removed earnings power from the Company.

As we monetized and securitized regulatory assets we removed them from rate-base, and the earnings power of the Company. So 2002 was a trough at $1.08 per share. And we have been building steadily now as we have been redeploying those monies in our business. 2005 we're projecting $1.45 to $1.35, so midpoint to midpoint, '04 to '05, that represents about 8 percent growth for the Company.

A little bit more on what happened in 2004 that is year-to-date earnings for each of the companies. CL&P increased its earnings about $6 million over this period year to year, really driven by transmission and distribution rate increases. Rate increases are covering not only cost that we are incurring in this business, but to recover the return on and then the depreciation of this capital program.

Now keep in mind running through all of our companies really are costs that we're seeing for employees. Expenses for pensions, for interest, for O&M. But these rate increases and the rate settlement that we will be touching on shortly recover those costs and allow us -- and put us in a position to earn the returns. I will detail that bout in a little bit for you.

Yankee Gas picked up 4 million in this period, importantly -- primarily because in 2003 there was a negative adjustment in their unbilled revenue equation. That did not occur here, so a pickup from about 2.5 million to 8.5 million. Western Mass without immediate rate relief or without rate release on the horizon has been bearing some of these costs, the pension cost I made mention of, depreciation and interest costs as well.

The Merchant Energy business had abour a $5 million pickup this year, 22 million to about 27 million, because of what we have seen as really a growing book of business. Not only is it growing and not only is it profitable, but it is more diversified than it has been. I will share a little bit more in the way of detail there, but primarily in the past we were focused on the New England marketplace, but we're having very good success now in PJM, so growing and diversified Both the businesses.

The services did experience a turnaround and loss year-over-year period about $3 million, primarily because they're not renewing government contract work. So which have to do with the Department of Defense has been reduced relative to last year. And they did have a $1.8 million after-tax write-off in the second quarter of this year related to a large contract.

I want to look at 2005 in a little bit more detail then by business segment. And these will line up against 2004. And this is how we will project going forward then. The regulated distribution and generation business will climb from the 91 to 95 cents, now 96 to $1. That represents about 70 percent our business. Transmission and the competitive companies, 26 cents to 30 cents. That is equally about 20 percent of our business. And going forward I think you'll see a little bit more diversity in our earnings. There will be more weighting given toward the transmission business as they deploy the $1 billion plus of capital, and less from a concentration or a market share perspective from our competitive businesses.

The parent will actually experience slightly larger losses this year. Again, as a result of interest expense. They have a LIBOR-based loan or a LIBOR-based exposure, and we see those rates climbing as the Fed continues to tighten. So all in all, $1.35 to %1.45 a share.

A narrower range that we've used in the past. And I think in part because we are increasingly comfortable with the earnings that are being generated in the Company, particularly utilities, as they have rate cases (indiscernible) over the next year or two or they have settlements. Certainly Yankee Gas settlement is pending. So we feel comfortable with this range. IT is based on 128 million shares outstanding.

I want to spend a little bit of time talking about the capital investment story. I think many of you have seen these types of statistics in the past, but this chart illustrates in blue the level of CapEx that the Company is planning on. It is very closely tied to the major projects that (indiscernible). So if the phase 1 project in southwest Connecticut and the phase 2 project in southwest Connecticut go online on our planning schedule, and the LNG facilities and large projects are done, this is about the level of capital that we will spend over this time frame.

In green we show the level of depreciation. The graph is just meant to illustrate that in terms of adding to rate base, the CapEx outweighs the level of depreciation by a very significant amount. And that is important because rate base is the earnings driver for the Company. Here then graphically is the distribution and generation rate base company by company. Really driven and large part by CL&P, but all of the companies are putting forth a rate base program that will drive earnings in average, I believe, of 9 to 10 percent over this period. So growing from about $2.5 billion to about $3.8 billion over this five-year time frame. So that is really the earnings power that we're putting behind this Company.

I will talk a little bit more about how we finance this growth, but generally speaking in rates we have reflected a cash structure that is roughly 55 percent debt, 45 percent equity, and that is our plans going forward as we fund this growth.

The other driver that we discussed are rate increases. And you can see here a summary of these rate increases. Cheryl Grisé, the President of our Utility Group will spend a little bit more time on the details here. But it is an important part of equation because as I said earlier, not only does it help recover those costs -- the costs that we are incurring in our business, but importantly it recovered the return on these investments as well as the depreciation.

So CL&P has a four-year case in place now. They will be a $25 million increase that will go into effect on January 1 of this year, and then increases through 2007. But importantly in that case, in that docket that was resolved late last year the Commission granted a 9.85 percent ROE. We think with a combination of this rate increase and managing the business, this company will earn, and has a chance to earn, that 9.85 percent in 2005. Through midyear of 2004 the Company was earning in excess of 11 percent.

For PSNH they had a settlement recently approved. It is a two-step settlement on 10/1. A $3.5 million rate increase went into effect. And then on June 1 of next year, another 10 million will go into effect as well. There was no stated ROE in that case. They actually had a return bogie for the components of their rate case. Cheryl will talk on that in a moment. So we think in the year 2005 this Company collectively can earn 10 percent on the shareholder equity in that Company, and through midyear of this year was earning about 11.5 percent.

Yankee Gas as well, we have -- excuse me -- we've announced a settlement and the settlement is pending. And it will be approved, that is our expectation, over the next several weeks. It is a $14 million rate rate increase that will go into effect on January 1 of this year. There is a stated ROE in that case of 9.9 percent. The Company through midyear this year is only earning about 4.5 percent on its equity. We have known was an issue. It is the recent that we went in for a rate increase. And we believe that this case puts us in a position to ear that 9.9 percent going forward in '05.

And then lastly, for transmission they have formula rate, a forward-looking tariff that they file each year. We are currently in the process of developing that precise tariff. And it amounts to about an 18 to $20 million increase that will go into effect on January 1. There is no rate increase for the compliance sign with the FERC. And embedded in that filing and in that settlement is an 11 percent return on common equity for the Company.

In terms of the transmission rate base, again a driver for earnings next year and beyond. This is our projected growth. The first thing I think you notice about this graphic it is little more chunky than the distribution company, primarily because it's got very large three projects. Dave will speak to these projects, but generally this rate based growth projects that in the year 2006, the first major phase of our southwestern MT (ph) project will go into service. And then again in 2009 the second major project will go into service. So you can see the rate base growth really being accelerated in '06 and '09, growing from 500 million to about $1.7 million over time.

The same financing profile. Generally speaking 55 to 45, 45 percent being the equity. Let's touch on the financing piece of this, how it is that we look to finance not only today but out into the future. I think first we very clearly think that we're starting from a position of strength both in terms of our balance sheet and our credit ratings. I think we have been, and we have proved over time to be very good stewards of our balance sheet and of our ratings.

I think of you look at each of the credit ratings light by each of the agencies, there is interesting dialogue around the investment capital program that we spoke to, to return to about the level of free cash that Company generates. I think it is important for you to understand, we say here in the second bullet that we're going to be doing financing each and every year. And I think that is true in large part to fund the transmission program that is housed in CL&P and the distribution company. So CL&P coming to market with bonds don't break it out for transmission and distribution separately. But that is what the new money is for.

So if you look at free cash flow, you should expect that we're going to be free cash flow negative over the several of years. That is our business model. We're putting capital to work. We're building rate base. And we will fund with a combination of debt and equity. I will talk a little bit more in a moment on what we think that amount will be.

But no surprise then that some of the credit metrics are under pressure. FFO to total debt or FFO to interest expense. We watch leverage very closely, but I can assure you that this is something that is important to us and a priority. But you should expect that we will be free cash flow negative.

We have been in the market quite a bit this year for a company of our size. Each and every one of our utility has financed in the debt market. I will summarize that shortly. And I think it has been a good outcome for us.

In terms of our credit rating, this is in a matrix of where we are. I think first on the right Fricke (ph) affirmed our ratings in August of this year. We're a stable outlook. S&P confirmed our ratings and actually moved our outlook from stable to negative earlier this year in April, including the downgrade of NDC, that is our generation company, from investment grade to noninvestment-grade, primarily as a result of them being concerned about a contract that runs between this company, NDC, and Select Energy. The term of the contract is short. It expires in 2006.

And they were further concerned that even if it gets extended it may not be extended on as favorable terms. We believe that we will continue to extend that contract. It will always be an important part of the Select story. And that is primarily the Northfield (indiscernible) storage facilities.

And Moody's I think their outlook negative for both NU and CL&P. And I think that change was in May of last year. And those outlooks really I think center around their concerns over the size of the capital program, and they plan to watch very closely on how we fund this program. As I said, they look at some of the metrics like FFO to total debt. Our coverage is eroding a little bit over time, but clearly that is a focus for us.

This is a look at our balance sheet today, just just one of those metrics. Right now not only for the individual utility but collectively for end use (ph) consolidated we managed it very deliberately. We have a target of 55 percent total debt to total cap. This does not include about $2 billion of rate reduction bonds, which have been issued at three of electric operating companies.

And importantly, these capital structures are reflected in rates, so there in our settlements, they are in our rate cases. And the cost of capital associated with this structure is being collected in the rate structure going forward. It will vary by 1 or 2 percentage points. You will see it vary over time. It looks as though we're pretty close at 54.6 now, but you should expect some change over time.

As I said earlier we have put into the market 5 issuances this year. We've taken the ten-year part of the yield curve and then more recently launder at 30 year. And the credit strike we think are quite attractive, 57 to 79 basis points for our utilities. And the ten-year, up to 104 for Western Mass. And the 30 year the deals have been brought to market quickly, efficiently, oversubscribed. And the Company is quite pleased.

We are active in the market right now with a follow-on issue for Yankee Gas. We did a private placement early in the year for 75 million. We're doing a private placement now for 50 million, 35 million of which is a refinancing for that company, and incrementally 15 million to continue to fund out their capital program.

We put this graphic together just to remind people and to demonstrate that in terms of liquidity and refinancing risk we have a pretty modest debt maturity and sinking (ph) fund profile ahead of us. With the exception that of an NU parent debt issuance in 2008, which is about $150 million, there is really is sort of clear sailing going forward. And we'd really do not see any difficulties financing on the future.

We are in the bank market now renewing our credit lines. Historically, at least over the last 4 years, we have had a 364 day facility in place. This is a fine source of our liquidity in the Company. We have just about closed out with syndication of the transaction. We've made some changes first. We're going from a 1 year facility to a 5 year deal. The bank markets are favorable. I think many of you know that. And we divide that between the family of companies that we have what we term as a regulated revolver. It was 300 million. It was going to 400 million, so we've increased the size here to fund the capital program to give us additional flexibility.

Then we have a revolver that we call the parent company. It is really there to fund the unregulated businesses. That is moving from 350 million to 500 million. That increase is to address a growing book of business for Select Energy, and also to address some of the FCC liquidity asset C (ph) ratios and some of the concerns there we have seen. So we really feel quite comfortable that under a stressed market environment or stressed credit environment that Select is well taken care here with the size of this new facility.

The cost of the facility is actually less than we have seen in the past. And we will see savings there that will flow through to not only Select, but for each of the operating companies. CL&P also has a receivables facility in place. They have had this in place for a few years, that continues to be there today.

In terms of borrowings, as we speak there are no borrowings, nothing outstanding under the regulated line. There are no cash borrowings under the parent line. There are 140 million of letters of credit drawn under the facility. It is a dual facility, both cash and letters of credit. And there are about 30 million of receivables sold under CL&P's line.

The system is actually still net cash positive. Still monies on the books from some of the asset sales. And in particular for NU the parent organization it draws about $150 million in cash linked, if not directly to the sale of Seabrook, to the larger amount of assets sold over the last 24 months.

More broadly then if we look at the cash requirements and the financing needed to support this capital program and this capital build out, we have identified above $4.5 billion of cash needs during this time frame. Really driven by a capital program that amounts to about $3.5 billion, but also parent (indiscernible) common dividends to our shareholders and other activities. This is generally speaking how we are going to financing these activities, between earnings, deferred taxes and non-rate based -- excuse me, rate reduction bonds, amortization. We've got about 1 billion 2 of cash coming into the business. Depreciation amounts to another 1 billion 4. And we expect at this time to do about $1.8 billion of financing.

Most of that financing, if not all, will be at the utility level. So those will be the issuers over time. I expect that we will continue going forward to maintain the financial policy of keeping this 55, 45 percent ratio. We will respond to concerns that we see in the market. We will respond to dialogue that we're having with the rating agencies. That's what our plans are built around.

I think, as Barry said, that if we spend our capital as we project, that is the capital we shared with you earlier on the slide, and it comes in on time, including the major transmission project, it is likely that through this period, and you'll issue additional common shares, we actually fund the equity now through NU's contributions of cash into the utilities.

The unregulated companies going forward we project will actually generate free cash, and provide that cash back to NU, who in turn will invest that into the utilities. But is likely that NU, bigger picture, will need common equity over this time frame as well. That is fine. We are comfortable with that. It is all part of the earnings model. Negative free cash flow is part of the earnings model. Issuing common equity to put it at work so you have competitive returns is also part of the model. You should expect that.

To just shift a little bit and spend just a few moments on the competitive businesses, if I could. This graphic illustrates to the left that we're now in the seventh quarter of posted -- the seventh quarter in a row of profitable returns for this business, including the 4 million that we announced earlier this morning.

On the right we show that in 2003 the Company earned $32 million. That is before the standard market design write off, but in terms of operating results $32 million, a range from '04 (indiscernible) that 30 to -- 33 million growing upwards of 33 to 39 million in the year 2005.

I mentioned earlier that we project these companies to be cash flow positive primarily from NGC, who the contract with Select. Between the two companies their generating about $100 million of funds from operations. Up to half of which to be flowed back to NU parent to invest into the utilities. And we think that is a good profile for a business that has what we think of as a fairly well-balanced risk profile.

A closer look at actually where these margins are being generated. You know that our Merchant business is a wholesale business and a retail business. We're not a trading organization. We sell power to customers. Customers who use power primarily on the wholesale side, and the standard offer and default marketplace on the retail side to industrial and commercial customers. Right now on the wholesale side about two-thirds of our business remains in New England. We've got about 3,800 MW there in New England against the peak flows in our book of 5,700 MW. We have had (indiscernible). I will share a little bit more activity there with you. And then on the retail side a book of business that is more evenly spread at about 1,800 MW. So 7,500 MW currently of load obligation in our book today.

This is a listing of the contract that has either been secured by Select Energy or that are in the marketplace today, or the pipeline going forward. So this is our bread and butter activity then, bidding into the supply obligations, the default service, the standard offer service. Pretty much in our 11 state footprint, which is again New York, CJM, ISO New England.

So in the book today is a load of -- here we have listed six contracts about 3,500 MW, including our own affiliate Western Mass. But this is in fact our major client list, a customer list, NSTAR, National Grid. Most of these transactions we see in this standard offer market are 1 to 2 maybe 3 years (indiscernible). That is pretty much our marketplace. And that is about the length and duration of our book.

Right now in the market is a 2,500 MW yellow for NSTAR. In the next couple of weeks our own affiliate, CL&P, will announce the transaction for up to 3,900 MW. That will be for up to too years for the year 2005 and 2006. And then you can see a host of transactions that total about 17,000 MW. These are deals that we have chased. These are the deals that we have proven we can be successful in. Very often several weeks after the transactions we announce the successes that we've had. But this is where we are today in terms of what we can announce. So about 3,400 MW in the book, 17,000 MW at play (ph).

And then lastly, just a quick snapshot of the retail book, we don't spend out as much time on this. They're having a good year this year. They serve about 18,000 to 19,000 customer accounts throughout these three markets. Most of these are large industrial and commercial accounts. Most of these contracts in the 1 to 2 year time frame with a peak load of 1,800 MW. We also have a gap (ph) business, about 10,000 accounts there with an annual load of about 37.5 Bcf.

I'm going to pause at this point. I am going to turn the presentation over to Cheryl Grise, who is the President of our Utility Group.

Good morning everyone. Still awake out there with us? I'm going to focus on the delivery and generation components of regulated business. And then when I am done, Dave Boguslawski, who is our Vice President of Transmission will come up and talk about our transmission business. So the balance of our presentation this morning is really going to be regulated business focused.

When I think about what it is going to take to be successful in the businesses that I manage cover the next several years, there are two things that I focus on. No. 1, we must manage our regulatory relationships and processes exceedingly well. You have seen from what Dave has discussed already this morning that we have a number of settlements in place. The future is fairly clear for some of our companies with respect to our regulatory deals for the next several years. But we must continue to manage that process extremely well.

Secondly, we have to operate and execute operationally very, very well. That is the price of keeping our strong relationships with our regulators and our credibility with our customers. So two key things that I will be pushing my organization to focus on.

We have a large capital program that I will talk more about in a few minutes, but importantly I think is for you to understand our regulators have a tremendous amount of support for we're doing. Chuck talked about the investments that are very much necessary to be made in the delivery business in the coming years. Our regulators see ay that need and are willing to have our customers spend their money to do that. And that is of course for the benefit of our shareholders.

Timely rate relief. We can't invest these dollars and not get them recovered in a timely manner. We think we have a process in place and a very clear path to get that timely rate relief. Strong reliability in customer service as I said. If we falter on those, we will lose the regulatory credibility we have developed. And so we cannot lose sight of that and we will continue to focus on that.

And then improved cost of management. I'm sure you're going to hear that from every utilities you speak with here in the next couple of days. But we cannot take our eye off that ball. We will be doing more with automation. Some of this capital investments that we will be making will be focused on automation. We're in labor negotiations in Connecticut and Massachusetts now. Our work practice changes must change. We cannot work to the work practices of 30 years ago and improve our cost structure. So that there is much to be done there, and we're very focused on that. And I want make sure that you take that message away.

As you can see, in the distribution and generation pieces of our business alone we're going to be spending quite a bit of money in the next several years. This actually gives you almost a decade long picture of our capital investments. And as you can see, we will be averaging well over $400 million over this time frame. And I think want is also important for you to see is that we will be growing our rate base over this time frame, which will of course will allow our earnings to grow over this same period of time.

So you see on key rate decision. We have alluded to that this morning -- a number of times this morning. When I talked to last year that was pending. We received a decision last December, and it was good in some respects and not so good in other respects. And we asked our Commission to reconsider that decision.

Happily this year in August they did reconsider that decision and restored some of the things that they had taken away. Most importantly, there was a reversal of a pension asset write off that had been ordered in the December decision. And that resulted in August of -- in the third quarter of about a $10 million benefit. And we will see additional pretax benefits of about $4 million in each of the next three years as a result of that decision.

You also see that we have a past of rate increases that are known, predictable over the next three years in Connecticut. The procurement fees which will be available to us through 2006, it is worth the half mill that is essentially a guaranteed fee. It is worth about $12 million on a pretax basis. And the other quarter of a mill, which is based on a comparison of how well we do from a cost standpoint of procuring power versus other in the Northeast, that is going to add up to another quarter of a mill, or about $6 million on a pretax basis. And we expect, based on what we know that we will be able to earn that this year.

In transmission, we also have approval for a transmission increase in 2004. I often get the question of how do you recover increasing transmission costs? You have this end, but as you are spending more in transmission, how are you going to recover that? The path is not entirely clear. It will be something in Connecticut short of a rate case. There will be some sort of a proceeding. We were unable to get an automatic tracker in Connecticut. But I can tell you there is strong regulatory support for timely and full recovery of transmission investments. So that is not something that we're concerned about being able to do.

And finally, we were awarded an ROE of just under 10 percent, and are quite confident we can earn that. And the 985 that we were allowed to earn as a return is exclusive of that procurement fee just mentioned in the second bullet here.

I am showing you this slide on the bill components in Connecticut because I think it is important for you to see that over half of the bills that goes to the customers in Connecticut comes from the cost of generation, the cost of congestion, the liability must run contracts and other such costs.

We believe that the proposed transmission investment that we will be making in the coming years will help contain those costs, to get those components down to customers. Clearly we cannot continue to see rates go up in Connecticut at the rate that we have been seeing. And there must be ways to bring those costs down. We think transmission is one of the answers to doing that in Connecticut.

I would also point out that the stranded cost charge that you see here, it is the brown number -- I think it is brown on your chart -- yes, brown. That will be going away in the year 2010. So that will be a component of the bill that customers will no longer pay after 2010.

In the rate case decision that was issued in Connecticut in December of last year, they did support a very robust distribution capital investment program. And this slide simply gives you a sense of the areas that we will be making those investments in. Almost half of what we will be spending will be on maintenance capital and load growth. But as you can see on a left side of that pie chart, we will be investing in replacing much of our aging plants, making reliability improvements, and also very importantly making technology investments.

Moving up to New Hampshire. It is always nice to tell the New Hampshire story because it is one that improves from year to year when I'm able to talk about it. We did reach a rate decision with those regulators this past summer. And have just put in the first of two rate increases that were agreed to, $3.5 million this year and there'll be another one June of 2005.

As Dave mentioned, there was no specified ROE in that case, but we certainly expect to earn around or at least 10 percent in New Hampshire this year. We asked for a transmission tracker that as we did in Connecticut, and we were equally unsuccessful in New Hampshire.

We don't expect to make the level -- nothing near the level of investment in New Hampshire in transmission that we will make in Connecticut. So the need for rate relief there for transmission costs will not be as strong as it is in Connecticut, but I expect that we will have to go back in for another rate proceeding to recover those costs when it is time to go back in.

And then finally, and I will be talking more about our Northern Wood Tower project, but our regulators there agree that that plant can go into rate base without the need for another new rate case, a strong endorsement for that plant up there.

This slide shows you PSNH's earnings power. And I don't show this for the other companies because I think the story there is a little more straightforward. In New Hampshire we have different lines of businesses earning different returns. We own generation in New Hampshire. We do not own generation in Connecticut or Massachusetts. We sell supply, about 80 percent of our load up there. And on our generation assets we earn an 11 percent authorized ROE.

Transmission, similarly we have a FERC mandated 11 percent ROE. And then in the distribution piece of our business, as I said, it isn't specified for us. That we would earn about 10 percent, we believe, on our distribution business in the coming year.

The Northern Wood Tower project, or the wood burning power plant as we call it inside the Company, did receive ringing endorsement from our regulators in New Hampshire. And we have actually had the ground breaking on that. This project is so favored in the state that not only did their governor attend the ground breaking last week, but Senator Judd Gregg came as well. And it is a neat little project because it is a win for customers. It is a win for shareholders, and it is certainly a win for our environment up there. We will be investing $75 million in this project, and expect it to be completed in about two years.

I draw your attention to the environmental benefits of this project. As compared to the unit that it is replacing, it will have 75 percent less noxs, 98 percent less (indiscernible), 90 percent less mercury, and it will be CO2 neutral. Just a wonderful little plant and a benefit for the economy in New Hampshire as well. The $20 million a year benefit is really to benefit the wood industry. That is exclusive of property tax benefits and others that will come along with that project. So a fun little project to do and something that is nice for our shareholders as well.

At Yankee Gas, Dave talked a bit about this already. I would point out that this slide says at the top of it, the Yankee rate decision. There is no decision yet. It is a proposed settlement that is before the Connecticut regulators for approval. But we have already reached an agreement with the Consumer Council and the prosecutorial division. And I'm optimistic that this settlement will be approved as we have filed it.

It will allow for a nice turnaround in earnings at our Yankee Gas Company when these rates going to effect next year. And we have agreed that we'll stay out until the earlier of mid '07 or the in-service date of our LNG facility that we have started construction on. So we think that things will turnaround. And I hope to have a much better story to tell you on Yankee Gas next year.

The LNG project that I referenced, again last year we were here awaiting approval on that project. We have received approval to go ahead with that. It will be about a $100 million facility. I am certain that I told you last year when I was here a price that was about half of that. What we have seen going on is steel prices of course have gone up dramatically, as well as the popularity of building those kinds of plants around the country. And so the cost of doing a project like this has simply doubled in one year's time frame.

We will -- we have signed our construction contract, and Chicago Bridge and Iron will be doing the construction of this plant. And again a fairly popular project in the state of Connecticut, which is hard to believe. Dave Boguslawski is trying to figure out how he can transfer that over to our transmission lines. But I think something that is contained in an industrial area in Waterbury, Connecticut is a lot easier to construct than transmission lines through Fairfield County.

And finally Western Massachusetts. I usually refer to that as my small quiet Company, but is the one where I will have the most work to do in the coming months most likely. Their restructuring rate freeze is expiring. And as we have come to the end of that rate freeze period we have seen our earnings start to fall off in Massachusetts. We are unable to offset the lower pension income and the higher O&M through growth, so we will need some rate relief.

We are talking with folks in Massachusetts about a potential settlement that would provide -- we would not go in for a rate case and do something that would hold us over for maybe a year or two before we go in. But it is too soon to tell whether or not that will be successful. I can tell you this. If we're not able to negotiate a settlement that will provide an ability for us to earn adequate returns on that business, we will be filing for a rate case very shortly in Massachusetts.

And in Massachusetts, we do have the benefit, unlike in Connecticut and New Hampshire, of tracking our transmission costs. So we're able to recover our transmission costs nearly real-time with spending -- our spending there. Although the spending in Massachusetts again is far less than in Connecticut.

So if I wrap up on my businesses before I turn it to Dave and give you one takeaway, it is to know that I think our regulatory relationships are good and improving. It is something that we are very focused on. It is -- part of our strategy going forward is to make sure that we continue to manage those relationships and outcomes extremely well. And secondly, we have to perform strongly from an operational and cost standpoint. My team is very focused on that. So with that let me turn it to Dave Boguslawski, our VP of Transmission, who will talk about the other piece of our regulated businesses. Thank you.

The only thing I would rather talk about than transmission these days is the Red Socks. I am pleased to be here today to speak to you about our plans and our progress. And we have made a lot of progress. I know that several of you have bought some of CL&P bonds and hold some of NU's shares, and I thank you for helping us carry out our plan.

I know as I speak with you this morning you are going to see what we see, which is our projects are needed by our customers, and by the region as a whole. They are supported by our regulators. We have clear plans for carrying out our projects and for cost recovery. And at the end of the day the investments will be good for both our customers and our shareholders.

We currently have $500 million in transmission rate base within the Northeast Utilities family. And we have plans to invest 1 billion to $1.5 billion over the next five years. I'm going to review with you the sighting of our large projects in particular and how that is progressing. And I'm also going to cover with you our cost recovery mechanisms.

But before I do, I just would like to touch briefly on who we are regulated by in the electric transmission world, because it is totally different than some of you may realize. First of all, we have an independent system operator in New England that we're trying to move into regional transmission organization status.

The ISO in New England actually leads and carries out a regional planning process that identifies where projects are needed. Our projects that you'll see me talk about are a part of the regional planning process that the ISO supports. Secondly, with respect to sighting, we go through a process within each state to sight our projects. Our largest projects are in Connecticut, and they are sighted and reviewed by the Connecticut Sighting Council, an independent group within -- an independent agency within Connecticut.

And thirdly as far as cost recovery goes, my projects that I am the building are regulated for cost recovery purposes by the Federal Energy Regulatory Commission. And if I receive FERC approval, which I expect to do, I then have the ability to build either ISO in New England or local distribution companies, depending upon which tariff the projects fall under.

Our growth plan has already begun. What you see in this chart is that we have gone from about $20 million a year in capital spending in '01 and climbed to 55 million to 99 million, and this year we expect to spend $175 million on capital in transmission. You can see we're actually carrying it out.

And then in subsequent years we're expecting to spend in the $250 million range per year roughly. The actual timing and size of those blue bars in the future years will change a bit as we go through the sighting process and the actual configuration of the lines that we're building change, and as the sighting process moves more or less rapidly than we built into these projections.

A couple of things I want to also point out in this chart. 2004 is a bit less than we have mentioned in our previous financial statements. We had a $270 million plan for this year, and we're coming in at around $175 million. That is primarily caused by delays that we put on ourselves to make sure we had more regulatory certainty before we proceeded with the Bethel to Norwalk projects pending, with the Middletown to Norwalk project, and with another project at an autotransformer in Haddam, Connecticut. So we intentionally held off on some of the spending to get that extra regulatory certainty.

You'll also notice that there is a jump in spending projected in 2008. For purposes of forecasting, we are assuming that most of the build for the Middletown, Norwalk project and the Glenbrook Cable project which I will cover in a moment, are happening in 2008.

Now this -- these capital expenditures you see here really, I think, of in two different buckets. Ongoing projects, which we have already mentioned to you look like distribution projects, and then larger projects. I am going to talk about both groupings.

First, the ongoing projects. We're spending about $60 million per year across the Northeast Utilities System. And I show you on this chart state by state what that spending is. 122 million in New Hampshire, 15 million in Massachusetts, and 220 million in Connecticut.

Now these projects are things like changing out circuit breakers in substations, building autotransformers to help create more of a power source from the higher voltage lines to the lower voltage lines. And we're actually reaching (indiscernible), adding bigger wire if you will to several of our lines. We have been doing this for the past couple of years. And about one-third or maybe more than one-third of the figures you see up there are projects already in the works and underway.

Now with respect to -- one other thing I wanted to mention is you'll also notice in the Connecticut box there I have mentioned that that Long Island Cable is something that I now consider to be an ongoing project. We still need to receive more permits, but I consider that process to be well in hand, well underway. And I expect us to be changing out those cables in the near future.

With respect to larger projects, I'm going to cover three projects, and they are all in Southwest Connecticut. First I would like to call your attention to the map that you see on the page, the map of Connecticut. What you see on the page is a yellowed section that is Southwest Connecticut. It is about a quarter of the state's geography. That consumes half of the power in the state of Connecticut.

I also show in this maps in green, green lines, where we have higher voltage lines, 345,000 volt lines in the state. We have about 400 miles of those higher voltage lines. And you'll notice there's none of them in Southwest Connecticut. So half of the usage in the state is the only portion of the state that doesn't have the higher voltage lines. And what that results in it is a transmission star (ph) section of the state. It is a problem that has been identified by the FERC, by ISO in New England, by us. Pretty much everybody recognizes the need for transmission in Southwest Connecticut.

And we have proposed three separate projects. The first are the ones -- the projects are the ones shown on this page, the Bethel to Norwalk projects. And you can see with the dashed line there, about 21 miles of higher voltage lines and 10 miles of 115 KV line. That project is already approved by the Sighting Council. We have actually started building the substations. And we are estimating an in-service state in the '06, '07 time frame.

If all goes as planned, we think we can finish this line in 2006. Again we are through the court appeal process as well, which the court recently dismissed the City of Norwalk's appeal, so we are about to be building the lines.

One other thing I want to point out in this chart is in the past we have disclosed an estimate of -- in the $200 million range. We are now saying that the cost is going to be about 300 to $350 million. And the reason for that is we have just gone out to bid for the largest portion of the line, the underground sections. And the cost have come in significantly higher than we expected. We expected some of it, because naturally with all that is happening with the cost of oil, that naturally spills over into large civil construction jobs. Digging trenchers in streets requires fuel, for example. Manufacturing cable requires fuel.

The price of steel is higher than it was. The exchange rates, the U.S. to the euro have moved. So we expected some of it. But the costs have come in significantly higher. It has caused us to go back and look at our entire cost estimating structure. And we now believe that 300 to $350 million is a more realistic range for this project.

In spite of the higher costs, there is no one that is doubting that this project is absolutely necessary. Everybody believes in this project. And in fact, the state is currently paying $125 million each and every year for emergency steps to wait for this project to begin.

The second project in Southwest Connecticut that we have proposed is what we call the Middletown to Norwalk project. It extends again in the dashed lines that you see here for 69 miles from roughly the Middletown, Connecticut area down to Norwalk. We are into the sighting process right now. We are well on our way through the sighting process. There has been many hearings held greatly. We expect the Sight Council to reach their decision in April. And we expect an in-service date in '08 or '09. The final configuration of this line will change between now and when the line is actually built, as the Sighting council is considering what is best for the State of Connecticut.

We share this project with United Illuminating. They are going to own 20 percent when this is all done, and we're going to own 80 percent. And we currently estimating a project cost somewhere in the $565 million range for our share. Again, that figure will change based on the final configuration and timing of the project.

The third project in Southwest Connecticut that we have is also in the sighting process as we speak. It is a 9 mile line that runs from Norwalk to Stamford. It is a lower voltage line, 115 AB (ph). It is all underground. The only controversy again is not about the need, because everyone knows the Stamford to Greenwich area is drying quite rapidly and needs more power. The only controversy is whether to take a southern Route, along (technical difficulty) or whether to take a northern route through more residential neighborhoods. And that will be the decision of the Sighting council in this process.

Turning now to how we recover the money that we invest. We have a tariff that bills most of our costs. Those lines that are considered regional in nature through ISO New England, who builds the region for usage. And the ISO bills rates on a state by state basis as the actual usage of power goes in New England. So you can see here what is important to us is as we build out the Southwest Connecticut system, Connecticut would paid 27 percent of the costs, just as they do with other projects in the region.

Any costs that are not recovered through the regional charges are then recovered under our, what we call our local tariff or our T10 tariff, which is in a make whole tariff. We look at our total revenue requirements, any costs we haven't recovered are billed in a formula kind of way so that we fully recover our course cost structure. That tariff, which is the one that we settled recently and FERC approved on September 15, it contains an 11 percent return on equity. And that return will be changed once FERC finally rules on our regional transmission organization finally, which I will talk about next.

We filed sometime ago with FERC to set up and convert the ISO in New England to a regional transmission organization. And we really do believe in that RTO. We want to move New England to the next phase of its evolution in a competitive model. We want to make sure that New England keeps a solid planning process to make sure infrastructures in place going forward serve the regional customers' needs. And we think the independent aspect of a RTO are very important to make the competitive marketplace work.

FERC actually approved the model that we filed. And so now it is a matter of carrying it out. And the RT0 will be set up early next year. And during that time FERC will also be holding hearings on our ROE, which we hope and we expect to come in at 11 percent or even higher, because FERC has rewarded utilities that form RTOs and build transmission around the country incentives. Still an open issue, but we do at the end of the day hope to see that 11 percent return on equity go higher.

So I have covered with you this morning what I think the important parts are of the Northeast utilities transmission business. All of our projects are serving very important customer needs in the region. We have a solid plan to carry out the program. Our regulators are right with us on the importance of these projects. And we have a solid cost recovery mechanism already in place. The benefits at the end of the day are going to accrue to both customers and shareholders, and we're feeling really good about our plan.

I would like to stop now and turn the podium back over to Jeff.

Thank you all for joining us. We have some time for questions and answers. I know some of you may have one on ones to follow up on, but we would like to take some of the questions now if we can. Anybody? Yes.

(Inaudible question - microphone inaccessible).

For the folks who are on the webcast the question is what kind of impact will the transmission construction programs have on rates?

Since I'm the one that gets to deliver the bills, I will answer that question. We don't think that it will have a dramatic increase on rates at all. The reason I showed you the components of the C on P (ph) bill earlier is to show you that transmission is actually a small fraction, less than half of a percent on customers rates now. That may double in coming years, but still that would be less than a cent with respect to the total bills. I think it will be a small piece of that.

(Inaudible question - microphone inaccessible).

The question is when we think the local installed capacity charges may be implemented in New England, and what kind of impact that may have on the competitive businesses.

The timing of putting in place Lightcap (ph) within New England is scheduled for next year, but I think we are a long ways away. There's a lot of disagreement on the whole topic of Lightcap. The FERC has set for hearing several components of Lightcap, what the demand curves look like, the slope of the lines and so forth. There's a lot to be learned yet between now and the time the actual Lightcap market goes in place. So it would be difficult for me to speculate with you on exactly when. I know FERC would like to see it rather quickly. I know many of the state regulators would like to see it drag out quite a ways.

Back on the competitive businesses, Lightcap is just one of those additional regulatory issues. We have dealt with a number of those in the past. It depends to a very large degree on exactly how we think it is going to come out and where, and what the very specific contracts are that we have in those particular areas. So there's no general formula that if we will just do this and it will fix all of these issues. It is one of the things that the folks running the portfolio manage just like all the other risks, regulatory and otherwise.

(Inaudible question - microphone inaccessible).

Most of the context right now are in the 2005 time frame in that particular area.

Any other questions? None. Thank you all very match for joining us this morning. And we will stay here it if you have any follow-up questions.