Northeast Utilities (NYSE:NU)
Q3 2007 Earnings Call
November 5, 2007 10:00 am ET
Jeff Kotkin - IR
Lee Olivier - Northeast EVP, Operations
Dave McHale - CFO
Chuck Shivery - Chairman, CEO, President
Thank you and good morning and thank you all of you for coming this morning. This is a really pretty nice morning for us. I guess probably the more important thing that we did not put on your tables is that the New York Patriots won last night, coming from behind and that makes me very, very happy. We started the day off, I think, pretty well.
I want to talk just a little bit about some of the things that have happened so far and then I'm going to do something a little different this morning. I want to spend a little bit of time looking out, and actually looking out beyond what is in the current five year numbers and begin to talk about some of the trends that all of you are very familiar with, but that are hitting not only the industry, but are hitting in a particular way and what those challenges might mean for opportunities for NU.
David and Lee will then spend the rest of the time going through all of the financial and all the operational things and we think it's a pretty comprehensive package.
I also would like to thank those of you that filled out an online survey that we did just a few months ago. We appreciate your input, and in fact, some of you will see that some of the new information in the news release and some of the information in this presentation is a direct result of the input that you guys provided us. So I thank you for that.
Along that line, as we move through the year, to the extent there is information that we can provide that we now do not; or information that we do provide that we could provide it in a different way if you would please give Jeff Kotkin a call and let him know that. We appreciate your input and we try to make investor communications the best that we can for the benefit of all of you.
'07 is turning out to be a strong, very successful year. If we look at it from an operational standpoint, the Northern Woods project got finished very late last year but started working well in 2007. The LNG plant, $108 million 1.2 Bcf plant finished in July right on time, went into rates, and actually will save our customers money. We settled three of the four rate cases that we have, capital expenditures are increasing, or were increased in '07, and operationally the company is doing extremely well. Lee will go into some of the details around that.
'07, a pretty good year so far. We changed the guidance, as you know in the news release, and increased that. We do have the CL&P rate case that we're working through and we'll spend a little time chatting about the status of that.
'08, another strong growth year projected and we gave you guidance for that in the earnings news release. It looks like that's moving along well. 2008 through 2012, continued investment opportunities that have been identified and quantified. One of the requests that you asked us was to begin to give you, especially on the transmission projects, some of the key milestones that you ought to be able to look for to see how we're doing, and we will try to do that today. Clearly, as we move through earnings conference calls into next year we will continue to do that. We try to give you milestones that you can calibrate our success against as we move through those programs.
A pretty good five-year plan, pretty good outlook. Longer term outlook, I think there are opportunities for NU. They are clearly challenges for New England, but they are opportunities for NU, as we look as some of these trends that are hitting the industry.
One of the questions that I get asked time and time again, what are the key things that NU has to do to be successful? So we thought we'd just put them on a slide for you. First and foremost, is we have continue to execute. We have to run the company from an operational standpoint and from a construction standpoint very, very well. If we don't do that, all of these longer-term strategies really are for naught. So continue to execute successfully. I think when Lee comes up and starts talking about the progress that we're making on the operational side, you'll see that we have continued to do that.
Effectively deploy the capital that's in that five-year plan. Some of that's pretty much locked in right now. The three remaining Southwest Connecticut projects are on schedule, on time, on budget and the capital dollars are pretty well locked in, but there are some future projects that we will have to work through the siting process and through the regulatory process and do that in a way that we can deploy the capital that we have assumed we can over that period of time.
Then clearly, we have to manage the regulatory business model in a way that we earn a return on the capital that we deploy. I think it is incumbent on NU, it operates in three of the six states in New England, our customers are very important to us and it is incumbent upon us to develop and deliver solutions that meet the regional energy needs and that's where I want to spend just a little bit of time with you this morning.
New England is dealing with a series of energy challenges. High fuel prices, a tremendous reliance on natural gas generation, natural gas sets the clearing price about 90% of the time in New England, and led to high fuel prices and high electricity costs and clearly all of the issues associated with that.
Peak load is increasing faster than base load. That drives a variety of different ways to look at distribution requirements. It drives a variety of ways to look at generation requirements, and it gives us the opportunity to do things to shave peaks. Whether that's energy efficiency, it simply brings down the total amount of energy that we use or whether that's some kind of demand response, peak shaving techniques that begin to bring down the peak. It does give us opportunities to begin to deal with an issue that New England sees. Of course, the renewable portfolio standards and RGGI. I'll spend just a little bit of time on those.
Every state in New England has renewable portfolio standards. You can see by the slide that they differ in each state, they typically advance over time. Definitionally, they're different. What counts is as a renewable generation source in one state may not count as a renewable generation resource in another state, but there is a requirement to begin to meet all of those renewable portfolio standards.
We expect that by 2015, New England is going to be about 1,500 megawatts short on renewables. That short position will not be distributed evenly across New England. The northern part of New England probably is slightly long, the southern part of New England we would expect to be very short. We're going to need to deal with complicated system planning issues around renewables and clearly it gives us the opportunity to build and strengthen the transmission grid.
If any of you have talked to any of the technical experts at ISO, you know that as renewables become probably more than about 15% of the total capacity on the grid then things have to happen differently. They have to deal with the intermittency of renewables and the fact that sometimes when you most need them, they're not available. It adds a complicated challenge to the transmission planners, it adds a complicated challenge to the system planners, but it is something that we will be dealing with in New England and I think there will be opportunities for us.
This is just a little slide that shows what we think are the growing gaps, essentially, between the renewable portfolio requirements and the amount of renewable generation sources that we have. By 2020, RPS requirements could be slightly less than 20% of the total system energy requirements. That equates to a gap of about 17 million megawatt hours or about 11% of the energy requirement in New England. We have got to do something about this.
The gap exists. We don't believe the gap can be filled with existing or with planned generation currently in New England. There is right now about 1,900 megawatts of proposed new renewable resources in the ISO New England generator queue with 1,500 megawatts of that coming from wind. If all of that is approved, sited and built, we still project that there's going to be a gap of about 11 million megawatt hours. That's about 3,100 megawatts of wind, that's 2,000 additional 1.5 megawatt wind towers, just to put that in perspective for you.
Now you can get different numbers depending on how you think about energy efficiency and how you think about demand side management. Those numbers can move around a little bit. But I think the message that we see clearly is that New England as a region, with those renewable portfolio standards, needs to begin to look outside of the region to meet those requirements.
The RPS standards may not be the worst, or the most stringent. If you overlay RGGI on top of that, RPS standards typically are a percentage. So if you can change load growth, you can actually change the amount of megawatts requirements for the renewable portfolio standards. RGGI is an absolute number; so many tons of CO2 emissions. Right now, the RGGI requirements that will probably start at the beginning of 2009 would force New England to bring carbonations back to 1990 levels, that's a cap of about 56 million tons. Beginning in 2015, that cap goes to 90% of 1990 levels, which brings it down from 56 million to 50 million tons.
In 2005, New England CO2 emissions were about 60 million tons. So in 2005, we are already at least 4 million over the first standard and potentially 10 million over the second standard and if the growth in energy requirements is about 1.3%, which is about where we expect growth to be in New England, C02 emissions grow to 74 million tons by 2020, which is a 24 million ton gap with the RGGI requirements.
To put that in perspective, it means 36 million megawatt hours of CO2 emitting generation needs to be replaced with non-CO2 emitting sources. That's about 5,000 megawatts of base load generation, at a time when a lot of base load generation is not being built in New England.
Even if DSM and energy efficiency hold energy growth flat, we've still got about a 10 million ton gap. We are going to have to do something about this and those challenges provide opportunities.
This gives you two pieces of geography. One is the northern part of New England. You can see the biomass and wind opportunities that are there, nuclear. The other side is eastern Canada, hydro opportunities, wind opportunities and at least in New Brunswick, the desire to build a new nuclear plant to the extent that they can find off take agreements in New England to help provide for the capacity of that plant. Canada may be a source that allows us to meet some of these new stringent requirements.
Clearly, if Canada is a source, there is some electricity flows that have to happen. There are a couple lines right now into Canada. There is some upgrading of some lines between New Brunswick and Maine right now, but it's not sufficient. If Northern New England has renewables, we're going to have to strengthen the north-west or the north-south transmission corridors in order to do that, to bring those renewables into the rest of New England.
If we do things in Canada, whether it's wind, whether it's hydro, whether it's nuclear, there's going to have to be some transmission systems built that will strengthen and allow that power to flow. These are not a depiction of any particular route, but they just simply give you a picture of what may be possible going forward.
We put this slide up just as a way to put it in perspective of what New England needs and what NU is doing. New England needs resources assembled to meet the opportunities. NU has organized an internal team to define the issues and develop solutions. Jeff introduced Jim Rob, our new Senior Vice President of Planning and Development. This is one of the two or three assignments that Jim has, is, okay, how are we going to do this? What's it going to look like? How do we position NU to continue to be a leader and how do we come up with solutions that not only are beneficial to the region, but also are beneficial to our company?
Partnerships among key stakeholders are absolutely critical. We've already begun discussions with regulators, with legislators, with governors, with DPUC Chairman and with other utilities about this issue. We need to begin to define the discussion with facts, so ultimately we'll be able to reach a solution that is in the best interest of not only the region, but also hopefully our companies.
We need an expanded dialogue to identify a portfolio of solutions, and again as I said, we've been meeting with folks within New England and in Canada about the appetite to bring power from Canada into New England and what that would actually take. New England needs results.
The last statement there says we will put solutions on the table. We have to do that. If we talk philosophically, we'll debate things. We'll debate things to death. When you put a solution on the table, it focuses people's discussion. It may not ultimately be the final solution. But it does focus people's discussion and it brings a certain amount of rigor to the debate and we need to do that in New England and we expect NU to take a leadership position doing that.
It's an exciting time in this industry. There are a lot of opportunities as we begin to deal with regional portfolio standards, RGGI, energy efficiency, a lot of the new technologies that are coming along and we expect to be involved in all of those things, be right in the middle of it for the benefit of our customers, and be a leader in each of those areas.
Before I turn this over to Lee, there's one other announcement that I would like to make. Another question that we received from a number of you, especially around the transmission projects, are do you have the components, the transformers, the cable, all the different pieces of the component parts to build these, do you have the labor to build them? Because you see what's happening across the country, but you also see what's happening across the world. You can see the shortages in those key commodities impacting companies' abilities to carry out their plan.
You have at your table, at your places a press release that was just released this morning by Quanta Services. Quanta is a national, very large transmission constructor. They have worked with us on a number of projects, in fact they're working with us very closely right now in the Middletown to Norwalk project and we are very pleased to announce that we have just entered into an MOU with Quanta so that they will provide the labor necessary to build about $750 million of that transmission build that we're going to see over the next six years.
John Colson, the Chairman and CEO of Quanta is here today. John, will you please stand up? He will be available after the program to answer any questions that any of you might have. We are really excited about this partnership. This is going to ensure that we have the labor. I think Lee will talk a little bit about the fact that we're making significant headway about some of the other component parts, but it will ensure that we have the labor to actually execute around this fairly aggressive transmission stance.
With that, let me stop and turn it over to Lee Olivier, our Executive Vice President of Operations who will give you an update on where we stand operationally; and then Dave McHale, our Chief Financial Officer will come up and talk a little bit about the financial ramifications. Thank you.
Thanks, Chuck and good morning. It's good to be here with you all this morning. Chuck talked a lot about the NU direction and the NU strategy. Of course, pivotal to that is our ability to execute around that strategy. What I would like to do with you this morning is update you on where we are in terms of our execution of our strategy. I would like to talk a little bit about our forward capital investment plan, where that money is going. I want to give you a status of our major infrastructure projects, in particular transmission, and give you examples of how these projects are improving reliability and at the same time in many cases, actually reducing cost as well.
First of all, our system reliability this year has been very, very strong, particularly at CL&P. If you remember last year, we had a number of outages in our underground systems. We've managed to avoid these this year. CL&P is on path to having probably its best year in reliability over the course of the last ten years as a result of the work we've done there.
We've also just recently successfully completed our North American Electric Reliability Corporation audit of our transmission operations. We were one of the first transmission businesses in the country to have that audit. That's really crucial, because that really helps to define what the risk profile is, particularly now that NERC can implement civil penalties of up to $1 million a day. We went through that audit, with no violations, no substantial findings. In fact, NERC said that we were really the standard setters inside of the industry.
In fact, we have brought in a very strong team of folks to run the compliance part of the business. They're all folks that have extensive background in nuclear, so they really understand what compliance is all about. We've been asked actually to speak in a number of venues about how we've done that.
Also, our capital program, a $1.3 billion capital program is on target for this year. Our spend will end pretty much on target by the end of the year. All of our major infrastructure projects are essentially on schedule and on budget. Chuck talked about the L&G facility that was completed in Waterbury, Connecticut. That facility was completed on time, on budget. The tank is full, it's ready for the heating season and I'll talk about some of the value that produces for customers in the next slide.
Also, our Bethel to Norwalk project, the first big transmission project that we built and put into service last year has really performed essentially flawlessly. It's been in service 100% of the time and is savings customers a significant amount of money. Our fleet in New Hampshire, our cost of service fleet in New Hampshire is meeting and exceeding all of our targets. That's mostly coal-based power plants and as a result of that we had the lowest overall average fleet cost in New England. Of course, that's the cost of service of the fleet.
Northern Wood Power Plant, which Chuck mentioned went into service late last year, that has run extremely well and is generating significantly below the market. I'll give you some idea of what that means in a minute.
Finally, our next major project, which is our NEEWS family of transmission projects, they are on track, we're making significant progress on those and I will update you on those on a particular slide.
If you look at where does the money go? It clearly goes into three buckets: into generation, distribution, and transmission. In generation, it's all essentially in New Hampshire and all tied to existing plants. We have no capital in our going-forward five-year plan for any peak in generation, either in Connecticut or in New Hampshire at this time. We have to wait to see what the outcome is of the docket in Connecticut. We will be submitting to the Connecticut GPUC in the January timeframe, a proposal to build peaking plants, but quite frankly we think probably the need for peaking plants in Connecticut is probably between 275 and 300 megawatts. So that proposal will be for a fleet size around 250 to 300 megawatts.
In New Hampshire, the two big bins are essentially an ongoing capital investment of $100 million to maintain the existing plants that we have. So that's upgrading those plants and really providing for the issues of obsolescence. The second major investment, the largest investment is in the Merrimack scrubber, which is a wet flue scrubber that we need that is required by statute to reduce mercury emissions at the Merrimack plant and I’ll talk more about that in a minute.
The distribution capital spend is really all centered around reliability. It's very similar to what you've seen before from the standpoint of improving reliability, obsolescence of equipment, supporting municipal entities in terms of moving power and overall trying to improve the reliability in all three of our facilities. That's $2.5 billion in this five-year planning period up from the last planning period.
Transmission increases by about 20% and increases particularly as a result of new transmission projects that we're bringing onto the table and will be started and in many cases, delivered over this course of the five-year business planning period.
Now, clearly all of these new projects will require a new revenue requirement. Literally, obviously, with the exception of transmission where we have FERC-based tariffs, we will have to go in for revenue requirements, but these projects save a significant amount of dollars for our customers.
In the case of the Bethel to Norwalk projects, we have saved as of October 1, over $130 million in terms of reducing congestion costs inside of Connecticut. The Middletown to Norwalk project will produce another $20 million to $30 million of savings in terms of reducing congestion further and our NEEWS project, we believe, will contain savings for Connecticut somewhere between $100 million and $200 million. If you look at the capital spend of all of the projects in southwest Connecticut, you're talking about $1.6 billion, $1.7 billion. When all of those projects have been completed and we have the revenue requirements, or the end rates, we're actually looking at a net reduction of about $18 per 700 kilowatt customer a year. So with all of that $1.7 billion in rates, the cost per customers will actually go down as a result of eliminating the congestion in those areas.
Yankee Gas, the LNG facility will save customers about $25 million, $26 million. When you net out revenue requirements, that's about $7 million to the good for customers. Finally, the New Hampshire plants generate $0.0783 per kilowatt hour, the lowest overall fleet cost. The average price in New England is somewhere up around $0.12 per kilowatt hour, so it's about a 33% reduction.
The Northern Wood power plant, that actually dispatches at a negative cost of about $17 per megawatt hour between the price of biomass or wood versus gas, when you factor in the renewable energy certificates and production tax credits, it's a real boon for customers and shareholders get to split that as well.
Now, real quickly, looking at the generation again, most of that investment is in the Merrimack facility. The Merrimack scrubbers are a $250 million investment. About $215 million of that will be in this business planning period. Again, the scrubber is required by statute. It has a statutory recovery mechanism. We have just recently brought on the Washington Group, which are renowned in terms of their expertise as an engineering procurement and construction company, or EPC to help us build the scrubber. We are in the process of doing a final cost estimate on that now. We'll have that ready by mid-'08 and we'll go out for bids on the scrubber and start construction in 2009. It adds about 6 mills, on average, to the site. That's about a 440 megawatt plant. But those plants remain viable into the foreseeable future. Again, delivering low-cost power to New England.
The distribution spend is pretty straight forward, again. It's in the three buckets of peak demand load growth. Peak demand load growth has been growing about 3% to 4% in New England. The target is probably that that will lessen a little bit, probably more about 2%, 2.5%. The investment is in peak demand load growth, the basic business requirements as well as the aging infrastructure.
There is about $24 million of capital inside of this plan for automated meter infrastructure in Connecticut. We're awaiting the outcome of a Connecticut DUPC docket where we have submitted options to the Connecticut DUPC from a range of a voluntary AMI, which would probably cost a couple million dollars a year, to complete AMI, which would cost probably about $275 million of capital investment. So we have given them a range of seven different options. We expect to hear the outcome of that by the end of this month.
Transmission, the transmission spend continues to be robust. It has grown by over 20% and is really being driven by the RTO regional system plan, NERC reliability standards. You can see over the last few years we've gone from $2.3 billion, now up to $3 billion. We have a high degree of confidence in the projects and the deliverability of the projects and when they will come in service. So we have put in here the annual plant and service numbers, you can see the next couple of years, '08 and '09 will go up significantly as we complete the projects in Southwest Connecticut.
Clearly, the rate base will go from about $1 billion at the end of '06 up to almost $4 billion by the end of this planning period.
Let's take a look specifically at where the money goes. It really goes into four major buckets and the green bars that you see is really the closeout of the Southwest Connecticut projects. Two-thirds of that spend is complete as of today. All of those projects are on schedule and we'll talk about those in a minute. So they close out in 2009.
Now something a little bit different here. We have previously told you that the NEEWS project were projects that had both 115 KV underground overhead, 345 KV projects and we had a range of $1.1 billion to $1.4 billion. We're at that point in time where we have the preliminary engineering and the preliminary routing completed and so we've learned a couple things.
First of all, the underground portion of the 115 KV projects is now a separate and distinct project. That's the yellow bar and that will be about $350 million. It's separate and distinct because it is not at all tied to the remainder of the project. We will have to do that irregardless of what we do on the other projects.
The total cost of the project in this estimate is $1.4 billion and we believe that is conservative because when we finish the overlaying of the preliminary routing and engineering information against the most recent cost measurement in terms of materials and labor, the cost of that project will go up. I can't tell you exactly what that is now. We'll have a better idea of that around mid first quarter, so sometime around the February timeframe, we're going to re estimate that project. You can see the orange piece, which is the remainder of the 115 KV overhead, mostly in Massachusetts, and the 345 KV portions of the projects coming in about $1.1 billion. Clearly, we expect again to have an update in that timeframe.
The blue bars are the other projects. Some of them are very small projects, kind of inside the fence, substation upgrades, upgrading of conductor. Some of them are fairly large projects, like a project that we have other in eastern Connecticut. That's about $1.1 billion. The last time you saw that, I think it was like $660 million. So that has gone up as well.
Just an update on the Southwest Connecticut projects. Again, they're all on schedule and essentially on budget and the Bethel to Norwalk project actually came in about $15 million lower than we had predicted, so that's the final number. The Middletown to Norwalk project is about 52% complete. It's ahead of schedule somewhere around three to six months. Clearly if we maintain that schedule, the project will finish for less than its approximately $1 billion cost and you can figure AUFDC probably cost about $4 million to $5 million a month, so for every month we finish early, it would be less by that.
Again, Quanta, who was here today, is building all of the overhead on that project and I'm sure John is feeling good that every aspect of that is ahead of schedule and on budget.
The Long Island cables project is essentially under construction now. We are removing the old cables in the sound. Those are the oil fill cables. We'll be installing the new solid cables in the January timeframe. That project will be in service by midyear.
The Glenbrook project, which is an all underground project from Norwalk to Stanford, we had previously forecasted that at $183 million. It's $223 million as a result of difficulties we've had with civil construction, excavation and interference with other utilities.
When we look at the total of this or nearly $1.7 billion between what we already know on Bethel to Norwalk finishing below budget; where we are right now with Middletown to Norwalk that we believe that all of these projects will come in total on our underneath the originally set budget of $1.65 billion.
A real quick look at the NEEWS family of projects. It really does consist of four projects and this is a partnership that we have with National Grid right now, where National Grid is building transmission lines in Rhode Island that have to connect to our projects and they're also build transmission lines in eastern Massachusetts. You have the interstate line there which is essentially a 345 KV line. It connects a whole series of about seven power plants in that corridor into Connecticut. It takes about 850 megawatts of power plants that are already in Connecticut but are plumbed into Rhode Island then mixed with Connecticut plants. So when you finish these lines into Connecticut, it actually doubles the transmission transfer capacity into Connecticut.
Chuck talked a lot about renewable energy. To get renewable energy into Connecticut, which has a deficiency of approximately 900 megawatts going forward, you need the NEEWS project to bring renewable energy in from upper New England and potentially Canada.
The Springfield cables project that you see there is the underground portion of the project. Again, that's going to be a $350 million project. We're pretty firm on that price, it looks pretty good. The greater Springfield 345 KV creates a corridor around Springfield and Springfield has significant reliability challenges in the summer and also has, from Massachusetts, pretty much the only congestion left now in Massachusetts with InStar completing their projects.
Finally, the other two pieces of the project go down into central Connecticut, connect that 345 KV system down into southwest Connecticut, and so when you're done with these projects, the location marginal price in Connecticut will essentially be the same as it is with the other states in the region and you do away with a lot of the other contingency requirements that ISO New England has put in place.
This next slide really looks at the major milestone of both the 115 KV cables project and the 345 KV cables upgrade. I'm not going to go into that in any level of detail, except to say that we will continue to update you on our progress on that schedule and if should any of those milestones change, we will update you on those as well. But that's pretty much that family of projects laid out from a milestone perspective.
This slide looks at that purple part or blue part of the stacked bar. What you can see is about $1.1 billion of projects inside of that stacked bar. It's laid out amongst the three states. What you can see, clearly, is there is still more work to be done in Connecticut, but also New Hampshire grows, Philly significantly over what we have expended there in the past.
The keys aspect of this is about 87% of all of the cost here is for projects that are wither already in the regional system plan or are not required to go in to the regional system plan. About 13% of the projects are required to be in the regional system plan and not there yet. So we have a very high level of confidence on this particular spend.
As Chuck said, we really think one of the things that differentiates us from other utilities that are building transmission, is one, we have built major transmission lines, got them sited, done the engineering, got them done on schedule, on budget. We have the next big trough of projects coming in over the course of the next two years and key to all of this is if you look at what's happening to resources, both material resources, manufactured products, the prices of commodities and labor, we have locked those up.
The MOU with Quanta provides for about $750 million of our labor needs, we have about a $1.1 billion need in labor over the course of the next five to six years. That locks up about 75% of that. We have essentially rates that are fixed over the '07/'08 timeframe and we'll be negotiating over the course of this month the remainder of the contracts in terms of how we deal with things like various inflators and so forth. This is crucial for us.
The other part is materials. If you're following this industry, you know the time that it takes to get major equipment like transformers and cable in many ways is doubled and in some cases tripled. We need about 51 major transmission bulk transformers between now and 2014. We have 50 of the 51 all lined up. We have either purchase orders in or we've bought options. We only have one left, which we're negotiating now.
The other parts major equipment, such as cable, structures and towers we are negotiating and we expect to have most of those locked up over the course of the next few months.
So between the labor, materials, we've brought on the Washington Group to do our scrubber, one of the best companies in the world to do that. We have the Burns and McDonnell, who is the EPC for our major transmission projects and if you've talked to those folks, you can find out that their book is starting to close up. Having those resources locked up really lowers the risk around executing on our capital program over the course of the next five years.
This is a slide we put together just to show the various strategic relationships that we have. This is a worldwide network that we've put together in terms of sourcing very sophisticated components that you need to build transmission whether it's transformers, control equipment, undersea cable, underground cable, and not only have we bought equipment from these folks, we have been to every one of these facilities, we've inspected the facilities, we understand their manufacturing capacity, we've approved their quality control programs. They understand our engineering, so again we think these are the kinds of things to be able to execute going forward that you're going to have to do.
Finally, I just want to say that, as Chuck opened up, our execution has been very, very strong. With the type of capital spend that you have, not everything goes perfectly, but we're right on track in terms of our reliability, our execution of our major projects.
Our transmission CapEx program is up about 20% over the course of this five-year business planning period and we really do have our resources aligned around our plan, so we have a high degree of confidence that we can execute that plan.
Again, I think one of the unique aspects of these investments that many of them provide significant cost benefits for customers, which quite frankly just makes them a whole heck of a lot more salable. Things like the NEEWS project, as expensive as it is, regulators understand and other policy makers understand that if we're going to solve RGGI, if we're going to solve the renewable portfolio supply issues that we have in southern New England, we have to do these projects.
With that I would like to thank you all very much and I'll turn it over to Dave McHale.
Thank you, Lee. Let's see if I can just spend a few moments and translate this into some facts and figures. First of all, in terms of 2007 we already mentioned it, we are revising guidance. In fact, we are increasing guidance for the year following yet another good quarter for us. We have traditionally rolled out our next year's guidance at EEI. Again, we'll do that for you and you'll see the figures shortly.
The backdrop of our longer term plan is a new $6 billion capital program which also introduces 2012, we keep that five-year horizon in front of you. That of course is the very foundation of our rate-based growth; that, along with ROE improvement gets this 10% to 14% return or growth rate equation continuing to work for us.
I think it's worth saying and I'll spend a little bit of time and give you some specificity around capital, very financeable from our perspective and we as a management team remain very, very focused on the overall total shareholder return equation.
First in terms of the quarter, we won't go through this extensively, but I think if you look at the overall business, we earned $0.32 for the quarter, $50.2 million, up substantially over last year, up about 34%. If you look at the individual segments, each of those, particularly the distribution business, is up substantially. There's a little asterisk on this page. We have included here for comparative purposes the elimination of the one-time, $74 million tax benefit that CL&P received in the third quarter of last year, so year over year the distribution or the collection of distribution companies earnings up 100%.
If we look at what's happening with transmission, up 10% for the quarter, which is a little lower than our run rate and it's worth saying there too that during this particular quarter we did rebate or refund back to customers about $3.5 million pretax, it was about a $2 million hit on our earnings as a result of an ROE decision that we received from the FERC earlier this year.
If you look at the results through the first nine months of the year, equally attractive; again $173 million across the enterprise, $1.12 a share. If you look at the transmission business here, its results are up 31%. That's a better run rate overall. As Lee suggested, the projects are on track. We are deploying the capital and that rate trajectory is working for us and the overall distribution business is up 30% as well.
Let me break that one down a little bit, because it's worth focusing on. These are our four distribution companies and if you look year over year, all the results here too are up. Each one them has a story, but I think collectively for New Hampshire, Western Mass, and for Yankee Gas, a lot of this has to do with what we think are really constructive rate settlements that are now in place. You're seeing the full effect of that for Western Mass; less so for Yankee. That just went into effect mid-year. You'll see that in the ROE figures in one moment.
A little bit of a story for CL&P. CL&P, although earnings were up 10%, on an ROE basis, they continue to under perform, hence the need for the Connecticut rate case and we'll touch on that in a moment.
This is a relationship that we've shown you in the past. It's a correlation between our rate base and our net income. It's meant to demonstrate two things: (1) a very substantially growing business and (2) that there is a very tight correlation -- not a perfect correlation, mind you -- between the amount of capital in rate base, what's happening with rate base, and what's happening with our overall net income.
We finished 2006 with about $1 billion of rate base. So far right now, at September we're at $1.2 billion. We'll end this year in excess of $1.4 billion, right on track and it is driving earnings now at $57 million for the first nine months of the year.
Here's our guidance, we've actually refined and raised '07 guidance. If you look in the '07 current column, you'll see at the bottom of the page we have increased the floor from $1.30 through $1.45 and the high end of the guidance from $1.55 to $1.60. The components speak for themselves, but just to touch on it lightly. We have been telling you first about our competitive businesses that they are breakeven businesses, last quarter we changed that to modestly profitable.
I will tell you, on an operating basis, they earned almost $11 million for the first nine months. They have about a negative $2.8 million or so mark-to-market, but we do think that they will earn about $0.05 per share. It's worth putting that into our guidance. Equally, for NU parent we've had a range of zero to $0.05. It will be on the high end, around $0.05. We have narrowed the transmission business range down by about $0.05. That actual reduction in the range reflects some of the ROE refunds we gave back in the third quarter. It also reflects lower, below the line tax benefits.
Nevertheless, things there are working quite nicely for us and the biggest move is really with the distribution business. That $0.10 range we just split up $0.85 to $0.95 primarily as a result of some of the benefits that we are seeing there in each of the businesses, including, really driven by the rate settlements that we achieved earlier in the year.
As we roll out 2008, $1.65 to $1.95; although maybe somewhat of a wider range than we would normally print here, we've done that primarily because we are giving you this information in advance of the CL&P rate case and the outcome of that is on the horizon.
If you look at distribution generation, $1.10 to $1.25 is making some assumptions around where we can land and may land with CL&P rate case, but also giving some variability around that range. Transmission, $0.70 to $0.80. Importantly for NU parent, I think the date in which NU parent is actually making dollars will swing into a more normalized mode when we use all of the remaining cash from our competitive generation sale.
So typically instead of having interest income, they have interest expense. I think you'll see that pattern emerge and repeat through the life of our forecast. The competitive businesses, we still own some contracts there, serving them out profitably, but we call that a breakeven business for '08.
In terms of the drivers, what worked and what's working in '07, works again in 2008. A lot of it is the transmission investment and what's happening with the underlying rate base. In '07 clearly we're benefiting from the PSNH settlement and from Yankee. Also from Western Mass we see that leading to interest income for the parent.
Look forward to 2008, there's yet another driver. There's probably two key drivers, the CL&P rate case outcome and I'll touch on what's happening there, but also continuing to manage the costs within the business. We are seeing some stability around our underlying corporate costs, employee incentive costs, pension costs which is a nice trend for us relative to some recent history. Nevertheless, when we have looked at some settlements and constructed settlements we continue to track those types of items, particularly with our Massachusetts utility so we do not get earnings erosion out of those matters.
Let's look at ROEs, because this is an important focus for us and I know it is for you. For our distribution companies, we have an internal bogey, if you will, of 9% to 10%, which may sound modest relative to some other objectives or jurisdictions, but I think it's a fair, long-term expectation for us.
If you look at these returns across the board, we're showing improvement for each of the utilities PS&H up to 9.4. Western Mass at the high end of that range. Yankee, you don't see it yet, because we have only got one quarter of that rate settlement in motion, but I think you'll see that too work its way into this yellow range.
CL&P showed improvement over 2006. In fact, the 9% return for the 12-months ending September is a little bit of an anomaly. We don't think that's sustainable, clearly. We continue to project that by the end of the year we'll be back in that 7% to 7.5% range. They did benefit in the quarter as a result of some tax benefits that are nonrecurring, but as I said, at the end of the year, back in that 7%, 7.5% range.
If you look at the cases that we have completed, clearly in terms of the authorized returns, they are in that neighborhood that we are driving towards for PSNH, we have a $46 million rate increase that went into effect midyear. We also have a $3 million increase on January of '08 to reflect a step up for capital that we'll be spending. The idea being no need to come back in 2008 for another case given the revenue requirements and the growing rate base, $3 million ought to cover that. That $3 million revenue requirement was premised on earning a 9.67% return. Also keep in mind, they have a generation segment, that has a 9.62% return, it is a fully tracking rate base that we true up. So when we're making investments in the generation segment of PSNH, they earn 9.62% without a great deal of, if any, volatility around that ROE figure.
Yankee Gas constructed a settlement, it was $53 million gross, but due to the savings, a lot of commodity cost savings associated with the LNG facility, for customers it was only a $22 million increase even as we put into service a $108 million asset for Yankee, so a very substantial year-over-year improvement in terms of net income for that company. It was premised on a 10.1% ROE and I think you'll see that ROE begin to creep up into that neighborhood.
For Western Mass, this one seems like we achieved it sometime ago, but we also have $3 million coming in on 1/1/08. No specified return, but there is a sharing range outside of 8 to 12. when we begin to do sharing, I expect we'll stay in that higher 9% handle for that company.
For CL&P Distribution, this is clearly the rate case activity that we're focused on. As an organization, we're very deep into the process right now. I'll touch on the schedule in a moment. We have asked for $189 million of rate recovery or revenue in 2008, $22 million in 2009. That $22 million is a step up increase there too to cover additional CapEx spending and additional revenue requirements. From an overall predictability standpoint, customers know that there's not yet another $200 million rate increase looming for 2009. In our view it's a modest $22 million.
It's premised on an 11% requested ROE. That ROE reflects our decoupling proposal that we have initiated. I will tell you that in the overall hearing process now, there are two key interveners, including the [Austin] Consumer Council, and they are generally in the 9.6 range on their recommendations with their expert witnesses. Without decoupling, they do go on to say if the commission accepts our decommissioning proposal, which is a revenue per customer, they would move it down as far as 9.1. That debate continues on the witness stand.
Our capital structure is consistent with the types of targets we've talked to you about in the past. 45%, the way in which rating agencies study it. They include all forms of debt. If you pick up our filing today, it's 49.5% on a rate making basis. That's a little higher than last year, our last outcome was 47%. If you look at intervener testimony, their position would be keep it where it is, 47%. There is not a huge debate raging about the capital structure, but it is plus or minus a couple hundred basis points.
I mentioned decoupling. We have a revenue per customer mechanism. It does protect us against the underlying erosion in sales due to primarily, we believe, conservation and load management, demand side management that we will be putting forth going forward. It does not protect us against customer account risk. It does not protect us against weather risk, and it does not protect us against a management team who still runs the business.
This discussion often manifests itself in whether adjustments should be made to the ROE as a result of some views that we are shifting risk. In fact, this is a consumer council and intervener argument that we are shifting risk to customers. You have seen in other jurisdictions where there have been modifications, downward modifications to the ROE as a result of this. The company's position is that it is too early to tell what the impact of decoupling will be. No empirical evidence necessary that would result in a reduced risk profile for the company. Lots of debate right now about what the specific mechanism is and how it works. I'll be glad to talk to you about that offline, but it's a really critical part of our overall filings.
We are asking of $290 million of CapEx, which is up from $225 in the last rate case on a run rate basis. This does not include AMI. An important revenue requirement is tree trimming. Let me just cut to the chase and tell you we have wrapped up the initial round of hearings, we are moving into the late-filed or second round of hearings. That begins this week. We have a draft decision due by December 13, should be filed by the 27th, and as we have seen in the past, and the commission I'm sure reserves the right to modify that and ask for an extension, but that is the current schedule. If it worked out this way rates would be in effect on January 1, of '08.
Let's change subjects and look to the longer-term and Chuck and Lee talked about the $6 billion program. Here it is year by year. We have introduced as well in 2012, interestingly, which is largely driven by the NEEWS project, is the highest year that we have seen in all of our forecasts, nearly $1.4 billion of capital spending out through that timeframe. This graphic just overlays what we showed you last year. So if you look at those overlapping years, 2007 through 2011, relative to what might be in your models today, the program is up $950 million over that and then again, we introduced a 2012 that continues this CapEx deployment going forward.
It's worth saying also what's in the program and what's not in the program. We know that all of our Southwest Connecticut projects are in there, they're all concluded by roughly the year 2009. The NEEWS project is in there, it actually does span 2012. It goes into 2013 and you can see at the bottom of this chart, $100 million in 2013, but it's the 1.4 program that Lee spoke to. Our CapEx in the Connecticut rate case is loaded in it; our Merrimack project, only $125 million for AMI.
It does not include on the what's not box. No new CL&P generation, no new PSNH generation, does not include widespread AMI implementation at all, and certainly with respect to the opportunities that we've been talking about for Northern New England Solutions, Canadian Interconnect Solutions and the like, even though we think there are promising prospects there for offer customers and our shareholders, no CapEx dollars in that $6 billion program.
In many respects, this is kind of it. This is the summary slide you all have been waiting for. How does that CapEx translate into rate-based growth? While I don't have an overlay relative to last years, these numbers are up as well. We will be more than double rate base over this time frame, we'll reach about $9.4 billion in total rate base by the year 2012. We haven't changed our policy targets in terms of the types of returns that we think we can achieve. You see that at the top of this graphic. We haven't changed our overall view on the use of capitalization and leverage behind that. Still 45%, 55% for the utilities, up to about 60% for the consolidated business.
You can see here our blended returns for the transmission business. Keep in mind, there are regional and local components of the ROE and on a blended basis, we should get this ROE rising to about 12.1% by the end of this forecast horizon.
That mix, that rate base and those parameters support the underlying growth of 10% to 14% on earnings. I will tell you that it's weighted towards 2008. If you look at the midpoint '08 growth over midpoint '07 it's a 20% plus. I would like to sustain 20% through the next five years, probably can't get it done, but 10% to 14% remains the growth equation going forward.
In terms of rate-based composition then, it will take $4.5 billion to $9.4 billion. At the end of 2006, our transmission business was about 23% of our underlying asset base or earnings base. Fast forward to 2012, it becomes something like 42%. That doesn't translate exactly into earnings because the ROEs in that transmission business are a little wider than in the distribution business, more predictable than in the distribution businesses, arguably.
We've put this schematic together for you. I can tell you that if you look at contribution over time, something you know, of course, that has risen steadily, from 18% in '04 to more than a third of our business today and if you work through the math by the time you get out into 2012, transmission as a segment will be more than 50% of our company's earnings.
In terms of our ability to finance this program, we remain very, very comfortable. If you look at our balance sheet today, this is a consolidated view. Less than 55% total leverage. We've got about $2.9 billion of equity capital behind this company, 43% of the total. We had a fairly meaningful financing program for 2007. We've completed that program with a number of issuances by CL&P in September, $655 million in total. Every one of our utilities issued.
I can tell you the last few deals were done in a jumpy market, as you all know, but investors' appetite for first mortgage bonds and for our paper remains very strong. That gives me a good deal of comfort going forward that our program is highly achievable.
We do have the benefit of being long cash, but I think over the coming quarters, the balance of that cash will be infused into our utilities, particularly CL&P, and we won't be in a cash position. Not a problem, we've got over $1 billion in credit lines, unused facilities that remain available to us. As you know, and I'll touch on this, we had at this point a very conservative dividend payout ratio. That cash flow not putting a lot of strain on the company.
We have spent a lot of time with all three rating agencies this year. They understand our plan. They've looked at the results, they've looked at the financing strategy we have of firmed ratings across the board for all of our utilities. As I said, debt offerings that I think are being well accepted in the marketplace.
Let's talk about the words “modest equity requirements”. Here's our view of our cash needs over this forecast period. $6.75 billion in total to fund both the CapEx and our dividends. Certainly we'll use our cash, $350 million that's at the top of this graphic. At the bottom of the graphic, we're looking at over $3.5 billion of internally generated funds from this organization. We'll generate maybe about $400 million of cash flow this year going to about $550 million next year and by the end of the forecast horizon, you can see we'll more than double this year's cash flow, up to $850 million.
It doesn't mean that we don't have to access the capital markets, we certainly do. So here in blue you can see about $2.8 billion, I will tell you that that is largely going to come from utility levels, debt financings, $2.3 billion is our current estimate. In addition, we think that from a NU parent standpoint, we will need to go into the equity markets at least within the confines of what we showed you here today. We're estimating that will be about $500 million in total. Not exactly sure whether that's going to be solely common equity or a combination of hybrids, we think we have that option. We’re seeing that option being utilized in this market. Increasingly it's something that we'll continue to study.
I do not think and it's not built into guidance for '08 that there will be any equity issued in 2008, I think our first equity issuance might be about half of this amount and it might be later in 2009. Recall that we issued equity in 2005, so that would have been a four-year cycle between equity offerings and maybe deeper into the forecast horizon in the very late years. Maybe we'd come back for another half of this amount. So $500 million in total. That is built into all the numbers and the growth rates that we've showed you here today.
Let me just wrap up by telling you something I think you know. Certainly, as we build out this program, we are committed to our overall investment grade ratings, committed to the balance sheet, we don't think it's just about balance sheet. We think we'll have a continued focus on cash generation. That's why you see us pursuing, see what the rate base for Southwest Connecticut is, we'll also pursue and see what's in rate base for NEEWS. Collectively that gets the cash generation moving in the right direction.
We would also like to maintain our overall profile so that we can put more into this program, should we. So maintain our flexibility over additional investments. We won't be shy, necessarily. We'll be diligent and prudent about it. We won't be shy about using additional financing including equity if we have to pursue more CapEx but I assure you in our view, it will be additional but accretive, either in total or in specific projects to the overall story. That allows us to continue to focus on this total return, which balances both earnings growth and the dividend growth, clearly from an affordability standpoint and a payout point, there's room to move that dividend.
You know it from studying the facts, if we achieve 2007 guidance we'll be at about a 55% ratio. If we get the midpoint in 2008, the numbers probably work out to about 42%,43%, 44%. Certainly that gives us some latitude, but staring at a $6 billion capital program plus lots of additional investment opportunities on the horizon, I think it's diligent to keep looking at that overall balance and that overall mix, bottom line I think both elements are an attractive aspect to the total return. I think we can keep that moving going forward.
Jeff, I'm trying to be respectful of the time here. I'm going to ask Jeff to take control of the podium. We've got a few moments for questions.
Thank you very much. We'll take some questions and then we will stay around here afterward. We also have a visitation from 2:30 to 4:30 today. Not only will we stay around afterward, but folks from Quanta also will also stay around in case you have any questions.
With that, does anybody have any questions? All right, well thank you very much for joining us today. We greatly appreciate it. As I said, we will stay around here and if you have any questions, please either search us out up here or over in Europe 6 between 2:30 and 4:30. Thank you very much for joining us.
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