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Executives

Roni Cappadonna – GM, IR

Pat Reddy – CFO

Analysts

Barbara

Piers [ph]

Lasan Johong

Mark Reichman

Elvira

Spectra Energy Corp (SE) Spectra Energy New York Analyst Meeting Call November 17, 2010 8:00 AM ET

Roni Cappadonna

Good morning, everyone, if I could ask you all to have your seat here. Good morning and welcome to Spectra Energy New York Analyst Meeting here. We’re glad that you could join us this morning.

I am Roni Cappadonna from the Investor Relations Group at Spectra Energy. Some of you may have worked with Patti Fitzpatrick in the past and I have taken Patty’s position as chief new don inside the company here.

We’re joined today by Pat Reddy, our Chief Financial Officer. And as you probably know, this presentation is being webcast. So when we get to the Q&A here after Pat’s presentation, we’ll ask for you to wait for a mic for any questions that you may have.

As we get started here, I’d like to direct you to our Safe Harbor statement and also remind you that there is a Reg G reconciliation in your books in front of you.

So, with that, I’ll turn it over to you, Pat.

Pat Reddy

Thanks very much, Roni, and it’s great for us to be here. We always look forward to our New York trips, and especially after we’ve had a good quarter, it makes for a more pleasant meeting.

As we reported on our recent earnings call, Spectra Energy delivered ongoing third quarter results of $201 million or $0.31 per share. And we mentioned on the call that we’re pleased with our performance for the quarter and we’re feeling confident as we close in on the end of the year. As you know the fourth quarter typically is the strong one for us. Between our first and fourth quarters, we earn about 60% of our annual EBIT.

So we’re anticipating that if we experienced normal winter weather and if commodity prices stay about at this levels at they’re today then we expect to exceed our 20% earnings growth expectations for the year, our guidance was $1.42 for ongoing EPS, and we should be in good shape to exceed that.

Focusing on the third quarter, there were a number of key drivers that I just wanted to touch on. First in our core fee based businesses, which comprise US Transmission and Storage, our Distribution Operations at Union Gas, and our Gathering and Processing in Western Canada. These operations performed well that EBIT was up about 3.5% from last year. And these businesses are expected to experience steady, profitable growth from our expansion projects. We still expect about 80% of our EBIT this year to come from these fee based businesses with about 20% from our commodity exposed operations.

Second, our fuel services business segment experienced significantly improved earnings, primarily due to higher commodity prices this year. But while NGL prices have been right on track with what we expected, natural gas prices have been considerably lower and we’ll continue to watch natural gas prices as we put our 2011 plan together.

Third, we’ve maintained our focus on executing an attractive growth plan. And during the quarter through strategic acquisitions like our Bobcat purchase, which we’ll talk a little bit more about in a minute. Our project expansions at our fee based businesses as well as growing our footprint in our partnership with ConocoPhillips which is our DCP Midstream operations.

Next. Excluding the effect of – first of all, because we covered these figures on the call, I’m not going to go down by line of business and mention the changes in EBIT from quarter-to-quarter or year-to-date, you can see them on the screen. But I did want to take a few minutes to talk about what’s driving the improvements in our EBIT by line of business.

So starting with US Transmission, we had a couple of items that affected 2009 earnings in the third quarter that didn’t reoccur in 2010, and we need to exclude the effect of those two items, our EBIT actually increased a few million dollars over last year’s quarter. Consistent with our expectations, the segment benefited from business expansion projects previously placed into service, projects like Northern Bridge, Market Hub Partners, Egan Storage, and Algonquin J-2. These benefits were partially offset during the quarter by higher operating costs and these were primarily timing related.

Our Distribution business saw increased EBIT. The improvement was primarily due to increased usage by industrial customers, largely gas-fired power generation facilities, growth in the number of our residential customers, that market continues to grow for us, and lower operating fuel costs with lower natural gas prices that that helped us this year, and then we also benefited from a strengthening Canadian dollar.

Union Gas is particularly sensitive to weather impacts as you know, so the fourth quarter tends to be a big quarter for that operation. On a typical year, on average, we make about 30% of our EBIT in the fourth quarter assuming normal winter weather in that business.

At Western Canadian Transmission and Processing benefitted from improved results in the base gathering business, primarily driven by higher contracted volumes from unconventional areas like Fort Nelson, our South Peace Pipeline and West Doe partially offset by declines in conventional supply areas. We also benefited there from the effect of a stronger Canadian dollar.

And for the quarter, I think we mentioned on our call that our earnings at our Empress processing plant were down slightly. Despite higher frac spreads, we mentioned that we are having to pay significantly higher extraction premiums to third parties to attract gas to our processing plant and we’ll have to take that fact into account as we develop our 2011 plan.

Our fuel services segment, which represents our 50% interest in DCP Midstream reported higher EBIT and the increase in ongoing earnings there was primarily driven by higher commodity prices this year, plus a pretax gain associated with ongoing unit issuances by DCP Midstream’s MLP. These increases in earnings were partially offset by reduced volumes in the Mid-Continent region. And finally the other category are basically are our corporate costs.

Next slide please. This chart provides the comparison of EBITDA by line of business for the third quarter and for the year-to-date 2010 versus 2009 with the increases of nearly 8% for the quarter and 17% for the year-to-date.

Next. Turning to some additional items that impacted the quarter; the stronger Canadian dollar boosted our third quarter net income by about $5 million versus last year. Interest expense was flat year-over-year in the quarter. Our third quarter 2010 income tax expense from continuing operations was up compared with last year. The increase resulted from higher earnings and a slightly higher effective tax rate during the quarter compared with last year’s quarter.

Our debt to total cap ratio stood at 57% at the end of the quarter and we feel very good about our ability to continue to fund our operation and our ongoing CapEx program through a combination of internally generated funds and debt, while maintaining our current investment grade credit ratings. That’s a very important objective of ours. And as I’ll show you on the next slide, at the end of the quarter, we have total capacity under our credit facilities of about $2.7 billion, with available liquidity of about $1.5 billion.

This slide shows our liquidity position in more detail. And this amount of liquidity is more than adequate to support our operations and our capital expansion program.

This slide is a little bit out of order, it’s page 19 in your booklet. But I wanted to talk about the fact that at the time that we were spun out from Duke Energy in 2007, we told our investors that we expected to grow our earnings by investing about $1 billion a year in growth CapEx in attractive projects. We said that we thought we could invest those funds and earn returns on capital employed in the range of 10% to 12%. And we’re not only meeting that commitment, but we’re actually exceeding it.

Over the next five years, we expect to invest about $5 billion in expansion capital to realize an incremental annual EBIT of about $600 million to $700 million, generating returns on capital in the 12% to 14% range. So by the end of 2014, we expect to create incremental EBIT from capital expansions of more than $1 billion since we were launched in 2007, and it’s that growth that’s fueling our EPS compound average growth in the range of 8% to 10%.

I want to talk now little bit about some of the projects that we placed into service this year. By the end of the year, we will have placed five projects with $900 million of associated investment in either full or partial service, and we’ll receive $200 million in annual EBIT in 2011 and generate returns well above our targeted range, and I want to spend a few minutes to look at a few of these projects.

The first that I want to talk about is our Algonquin East to West project, which uses existing infrastructure on our Algonquin system to offer shippers the opportunity to reach growing Northeast markets, by moving new sources of supply into existing delivery points on our systems throughout the region. A kind of unique aspect of this project is that the gas moves from East to West which is kind of opposite the traditional flow pattern and it supports the delivery of LNG from facilities recently added to the Eastern portion of our system, you may know it as the accelerate LNG facility which attaches to our HubLine offshore facilities.

Then, our TEMAX/TIME III project we broke ground earlier this spring there. And just earlier this month brought into service the first phase of this $700 million expansion. The second phase is expected to come into service in the second half of next year. And this project will allow our shippers to receive new natural gas supplies from Western basins at various points along the Texas Eastern system through the enhancement of the existing mainline as well as incremental expansions.

Then, out then in Far North British Columbia, we have our Fort Nelson plant. We are making great progress on our multi-phased expansion there, which is increasing capacity in Fort Nelson British Columbia to accommodate Horn River gas. We recently brought back into service almost 0.5 billion cubic feet a day of previously laid up capacity at our Fort Nelson plant.

You may remember that as recently as three years ago, we’re looking at mothballing the entire plant as gas supply from the Western Canadian Sedimentary Basin, the conventional areas was trailing off. And you fast-forward to last fall, we signed up seven producers for about 800 million cubic feet a day of incremental processing capacity, about 500 million of which, as I just mentioned, is existing capacity we’re replacing back into service. And we’ll bring the total projects into full service between last year and 2013 so over about a three or four-year period of time.

We’re also making progress on expansion projects in the Montney region, South of Fort Nelson. Our new Dawson plant will be constructed in two phases of a 100 million cubic feet each, and we’ll process raw natural gas from the South Peace region and it’s targeted to go into full service in 2013.

So we’ve got a strong backlog of projects in various stages of execution. And on the next slide I’ll take a look with you at some of those.

This map provides a clear view of the projects that we have in execution. And there are two that are new to the map that I want to highlight. Looking first at the Southeast, in August, we closed on the acquisition of our Bobcat Storage Assets and Development Project. In addition to the purchase price, we expect to invest an additional $400 million to $450 million to fully develop the Caverns by the end of 2015. We’re in the process now of leaching Cavern 3 of a total of five Caverns. And when we’re finished, we should expect to have working gas capacity of about 46 Bcf.

Moving to the Northeast, we’re very excited about Texas Eastern’s Appalachia to Market project, something we call TEAM 2012. It’s a $200 million expansion of our Texas Eastern system and it will move customers’ gas supplies from the Marcellus region to our premium Northeast US markets. TEAM 2012 is our first expansion that’s fully dedicated to moving Marcellus supply to market.

Range Resources and Chesapeake Utilities have fully contracted the capacity of this project, which is scheduled to go into service in November of 2012. And we’re continuing with the development of our New Jersey - New York expansion of our Texas Eastern and Algonquin systems. This is a very important project for us and for our customers in New Jersey and New York. And we’re on track in these early stages of the public project. The next milestone for us is filing our formal FERC Certificate application next month with the projected in-service date in the second half of 2013.

So that’s a quick look at some of our most significant projects that we currently have in execution. Our other projects are progressing nicely as well. And we’re meeting or exceeding the expected returns on capital employed which is gratifying for us.

And looking a little further down the road at some of the opportunities that we have on the horizon, we see and continue to see very significant additional expansion opportunities in British Columbia beyond 2012. The Horn River Basin is estimated to contain some 500 trillion cubic feet of reserves and the Montney Formation is estimated to contain 450 Tcf. So combined we expect gathering, processing and pipeline growth opportunities well into the future for us.

We also continue to see growth opportunities along our system related to the plant conversion of coal and oil-fired generation to natural gas in the Southeast US, particularly in the Florida market, and that’s not depended just on resumption of growth in Florida, it also reflects the fact that a number of existing power plants that burn coal or fuel oil need to be converted not so much because of climate legislation, but because of existing SOx, NOx, and mercury limitations.

We also see opportunities in Midwestern states that have long relied on coal for power production, so we see opportunities related to power gen conversions primarily along our Texas Eastern and our East Tennessee pipelines. We also see opportunities for both Spectra Energy and DCP Midstream in the Marcellus region.

Recently, you saw our announcement regarding a Memorandum of Understanding to jointly develop the proposed Marcellus Ethane Pipeline System project or MEPS as we call it with El Paso Midstream. The MEPS project would transport ethane from fractionation plants in the Marcellus region to serve the nation’s large petro chem industry in the Gulf Coast area.

Then, in September, DCP Midstream and its MLP DCP Midstream Partners, entered into an agreement with Magnum Hunter Resources to gather gas for that company produced in the Marcellus area. DCP Midstream also continues to pursue attractive opportunities in the Eagle Ford and the Permian Basin areas. In the Eagle Ford, we have existing processing and gathering capacity there that we’re making use of.

And it’s worth noting that DCP is able to fund its growth internally by raising debt at the DCP Midstream level and by issuing partner units at the MLP, so that the parent companies Spectra Energy and Conoco don’t have to put funds into these businesses for them to grow. And at the same time we continue to receive significant cash distribution from DCP Midstream that we can then reinvest in our fee based businesses.

Again we are seeing excellent momentum and growth across all the segments of our businesses, which gives us confidence in our ability to deliver strong shareholder value through a combination of earnings growth and an attractive dividend yield.

So really, in closing, just to kind of recap, we feel like we’ve made very good progress on our capital expansion plans. Our core businesses delivered solid performance and we captured the positive effects of higher commodity prices at our DCP Midstream business.

You can see how well positioned we are in terms of existing and future expansion opportunities, reflecting substantial contracted growth that builds upon the strength of our diverse portfolio of our expanding footprint. We’re equally well positioned financially with strong cash flow, investment grade credit ratings, excellent access to the capital needed to fund our growth and attractive conditions in the financial markets.

So as we move through the fourth quarter, again assuming normal weather and that the commodity prices stay about where they’ve been recently, we continue to feel very good about exceeding our EPS guidance of $1.42 for the year.

And so, with that, Roni and I would be happy to answer any questions that you may have. And again, because this is webcast, if you could raise your hand and wait for the microphone, that will help the folks that are listening in. Roni.

Roni Cappadonna

Great. And if we could just pause a moment and allow the operator to give instructions for those on the phone to pose their questions.

Pat Reddy

I needed to talk a little bit longer so you could finish breakfast.

Question-and-Answer Session

Operator

(Operator Instructions).

Roni Cappadonna

Okay, what do we have here.

Pat Reddy

Hi Barbara.

Barbara

Good morning. You mentioned your commitment to investment grade ratings, but you’re mid BBB, so you didn’t make a commitment to current ratings. So can you elaborate on that please?

Pat Reddy

I should clarify that. Really our commitment is to our current ratings, BAA to BBB flat. We think that’s kind of the sweet spot for us on the debt side in terms of our overall costs of capital and it’s very important us to keep our ratios in line. And when we came up with our $1.42 guidance in January, we mentioned the fact that we prepare a three-year financial plan, so 2010 through 2012.

And as we looked pro forma our coverage ratios FFO to interest and FFO to debt actually strengthened during the three-year period particularly because of some of our projects that involved putting mothballed plant back into service, there is not a lot of cash outflow out front, but we began to get EBIT fairly early on. And so it’s kind of counter intuitive even though we are financing a good percentage of our investment in new projects with debt, our credit metrics actually improve.

Roni Cappadonna

Pat, we have a question over here.

Pat Reddy

Okay.

Unidentified Analyst

Yes, good morning. Could you talk about 2011 capital spending plans?

Pat Reddy

What I’ll say that we – just to back up a minute, our internal process for getting our 2011 plan and actually it’s a three-year plan that the Board approves in 2011. We go to the Board initially in October with preliminary figures for next year, including CapEx, and then we get formal approval after we do some fine tuning of the budget in the first week in December at that meeting, and then we’ll come out with our formal guidance and details about our CapEx plans in January of next year.

But we have said and we continue to believe that we’ll be investing at least $1 billion a year in growth CapEx. This year, our maintenance CapEx is $640 million. I think that’s kind of representative of our maintenance investing going forward.

Unidentified Analyst

Can you clarify those are exclusive Midstream, right?

Pat Reddy

That’s correct. DCP Midstream as I mentioned earlier is self funding. The sponsors Spectra Energy and Conoco don’t put capital into that business. You may, if you happened to have listened into DCP Midstream Partners third quarter call, they talked about an ongoing project that they have with DCP Midstream to co-invest in new opportunities as well as some existing plant in Southeast Texas.

For example, there was a dropdown that DCP Midstream Partners just issued units to help fund. And so we see the two of them working kind of in tandem over the next three to five years to finance growth with DCP Midstream as showing debt and Partners as showing equity units to keep their combined credit profile where it needs to be.

Roni Cappadonna

Pat, we have a question here.

Pat Reddy

Hi Piers [ph].

Piers

Could you comment on any trends you’re seeing in your sort of renewed contracts on your older pipelines like Eastern and so forth?

Pat Reddy

Every year the primary or the primetime for renewal for us is the month of October on our major systems. And we have a slide that’s in the book, probably in the supplemental information that shows kind of the average life of contracts on our systems. And at the short end, we have an average size of about four years on Texas Eastern. And then on our newer projects like Goldstream, it is more like 18 years or 20 years.

And the reason that Texas Eastern is only four years is that it’s one of our oldest pipelines that signed up twin-year contracts initially and many of those contracts have run their term. And at the end of the term have annual evergreen clauses that require if a party doesn’t wish to keep capacity they have to give us notice a year forward. And so in our October renewals, we experienced about 95% renewal of capacity. And as I mentioned we then had a year to remark its capacity that’s turned back. So fairly typical and not that significant.

Piers

Is the pricing sort of significant in the renewals?

Pat Reddy

Actually the renewals are at the same rate, typically at our max tariff rates. Our pipelines tend to remain fairly full as do competing pipelines in the region. And so there’s really not a lot of financial incentive for customers to say leave Texas Eastern and go to a competitor. I think what we’re seeing is with lower gas prices and more stable gas prices, some marketers are turning that capacity that don’t find the current environment as profitable as maybe it was in the last few years.

Roni Cappadonna

Right. If I could just ask the operator to give instructions one more time for those on the phone.

Operator

(Operator Instructions).

Unidentified Analyst

A couple of questions about your activities in the Marcellus. You mentioned that the TEAM project was fully contract.

Pat Reddy

Yes.

Unidentified Analyst

And I was just wondering what the – what’s the term of that contract was?

Pat Reddy

They tend to be kind of in the 15 to 20-year range and vary by contracts or by vary by party that we signed up, but I can check here specifically without kind of naming names. We have a – these are 16-year firm contracts with one party and 15 years with the other party.

Unidentified Analyst

Okay, so you filled it up before adding compression.

Pat Reddy

One thing I should mention as maybe just a general principle, and I think [inaudible] repeating because something that separates us from some other companies in our space is that we don’t undertake to orders deal or puts deal on the ground until we have a project that’s fully contracted. We also don’t oversize the project. So what you’re going to see for example is TEAM 2012, TEAM 2013 and as many expansions of our system as we need and increment as producers are ready to signup under long-term contracts for capacity.

And the reason we can do that – one of the things I really like about the place that’s Spectra is in right now is when you look at our footprint, our pipes are very expandable and there is kind of three ways to do that. You start by adding compression so that you can force more gas through the line. And then when that kind of runs its course, you can resort to what’s called pipeline looping, literally adding loops of life in parallel to your existing system. And then the third thing you can do and we are doing in on parts of Texas Eastern is pickup portions of smaller diameter pipe like 24-inch pipe and replace it with 36 or 42-inch pipe.

So I mentioned that because one of the slides, I think we showed that we’ve completed 42 projects since our spin in 2007, and they’re mostly what I call by-size or bolt-on projects, $50 million to $250 million, exceptions being Fort Nelson and our New Jersey -New York project, which are $800 million to $1 billion. But back to your point, most of what we’re doing is just incremental expansions of our existing pipes in the Marcellus.

I would mention to you that in the last several years, we’ve entered into more than 70 interconnect agreements with Marcellus producers where we are able to blend their gas that might be little bit high in ethane it might not on its own, meet pipeline quality specs, we can take that gas put in with the rest of our pipeline quality gas and blend it. Of course, there is a limit – there comes an end to how much of that we can do and others in the area can do. But I think it’s why you haven’t seen an ethane solution in the region yet other than the ones that have been announced like ours.

Unidentified Analyst

Yes, and actually moving to that, if I could, what is your outlook for the development of fractionation at the frontend of that project?

Pat Reddy

That’s something that we’re not currently involved in ourselves or companies like MarkWest that have fractionation capacity. I would say that when you think holistically about Spectra and DCP, we would like to on a kind of coordinated basis have a Marcellus strategy where our big inch pipelines are the mainlines that are used for transmission.

This partnership with El Paso would be the ethane solution to bring ethane down to the Gulf. And then through – probably through joint ventures like the one that DCP is pursuing with Equitable to enter into gathering and processing, whether that involves fractionation for us as well, I’m not sure yet, we may leave that to others.

Unidentified Analyst

Thank you.

Pat Reddy

You’re welcome.

Roni Cappadonna

All right, Pat, we have a question over here.

Unidentified Analyst

Good morning, Pat.

Pat Reddy

Good morning.

Unidentified Analyst

I just want to jump to Canada, and maybe you can talk a little bit about the – about efforts, I know it represents a pretty small part of your operating earnings. But we’re hearing that the premium you pay to attract volumes is increasing as the Western sedimentary basin falls off. And I was wondering if you can maybe talk about how that might impact in ’11 and what you’re seeing there and what’s the market dynamics are?

Pat Reddy

Sure. Well we – you’re right and that it’s significant enough for us to talk about, but in the overall scheme of things it’s relatively small. For example, this year our Empress EBIT was forecast to be $80 million out of a total EBIT for Western Canada of $380 million and total EBIT prospect for Energy Corp of just under $2 billion. So it’s just to put in context.

But you’re right, we have had to talk about the fact that at the beginning of the year, we try and give all of you rules of thumb so that you can take our guidance and factor it up or down for changes in oil prices, changes in the relationships of NGL to crude, changes in the FX, and so forth. And one of the metrics we’ve given you is the frac spread and how that impacts our Empress earnings.

We’re going to have to put on our thinking caps and figure out a different way to do that in 2011, because that relationship is kind of broken down, frac spreads are very high and so our extraction premiums. And so as we think about 2011, our EBIT from Empress is probably is going to be somewhere in the range of two-thirds maybe what it’s been this year is just kind of a rough guess at this point.

Unidentified Analyst

Okay, thanks. And then in terms of the Horn River and Montney opportunities, you were talking about 2012 and beyond there is an additional expansion there. Just wondering if we stay in an extended low gas price environment, where might we see the producer to pull back, I mean what’s their breakeven economics there.

Pat Reddy

Well, that’s a good question. We heard breakeven with the 10% return as low as $3.25 from one of the – one of our customers and one of the producers up there. What I always have trouble kind of putting in context is 10% return $3.25 based on what, all-in cost just – what costs were feed if some costs, is it the full cycle cost. And so I think that’s a question probably better asked to the producers.

All I know is that we have had a second round of nonbinding open seasons for what we call Fort Nelson 2, it would be beyond the 800 million expansion that that we have underway, very strong producer interest.

And the way it works is we had a nonbinding open season, then we enter into agreements with the producers that indicated interests where they backstop our development costs, which helps us to sharpen our pencil and refine our estimates of what the second round of expansion is going to cost and what the rate would be, and then that would lead probably in the middle of next year to binding contracts with those producers.

So they’ve committed to a fairly significant backstop of our development cost which says to me that they’re very interested in keeping that option open. What happens when we get to the middle of 2011 is a little bit up in the air to your point it really will depend on what happens with gas prices.

Another thing that complicates just a little bit is that as you know like in the Eagle Ford, the Eagle Ford has a lot more liquids than some other formations. And so if you can get six to nine gallons per 1000 cubic feet of liquids you can boost your effective price to couple of bucks at least per Mcf or per dekatherms. So you almost have to ask where is the drilling taking place, where is our footprint and that kind of thing.

But so far we haven’t seen a pullback in interest, but like you, we’ve got the same question of what point gas prices were continue to decline, would we see that pullback.

Unidentified Analyst

Thanks. And maybe just one last question, on the Mid-Con, you said volumes are decreasing there during the quarter and we’ve been hearing a lot of interest from producers to ramp up production. Just wondering when you might see that kind of pick back up and what basis it might be declining?

Pat Reddy

It’s kind of in the Permian area. And so the interesting thing is DCP posts on its website its margin by contract. And what you will see are volumes really in total are relatively flat, but what we have seen is a change in the mix of contracts of interchange and where we’re getting production. So – but we’re looking forward next year. We’re probably going to budget for volumes to be about flat. And in this year’s budget, we budgeted them to be up kind of a 2%, so we may start off a little bit conservative.

Roni Cappadonna

I think we have two questions on the line.

Operator

Your first question comes from the line of Lasan Johong.

Lasan Johong

Good morning. This is Lasan Johong. Hi Pat. Couple of questions. On – first of all NGL pricing, apparently there has been some shutdowns of fractionators in the Gulf Coast and there is some talk about NGL pricing decreasing in the next several months, and the increased liquids drilling is going to contribute to that and would put price pressure going forward in 2011 as well. Do you see any evidence of this?

Pat Reddy

Actually, we have, and again this is something that’s counterintuitive. We’ve spent a lot of time talking about this with our affiliate DCP Midstream which in some ways when you look out the forward curve, they are the market, and we also have had some consultants come in and talk to us. And it turns out that, I mean, it’s really a very complicated picture when you think about the fractionation capacity most of which is in the Gulf, there was some planned and unplanned outages over the summer, which caused NGL inventories filled.

But the other thing that people don’t often recognize is that going back about 2000, we’ve had annual declines in NGL volumes of almost 2.5% per year that needed to be replaced. The crafters are currently operating it about 95% of capacity and they are not getting enough domestic supply to meet that need and so inventories are being drawn down. So we’re actually seeing NGL prices pretty strong. For our average a barrel, this month, they’ve averaged about $1.70. You may recall our budget for the year was $0.95, although –

Lasan Johong

Yes.

Pat Reddy

Although we were budgeting it to increase during the year. So on balance, we’re – and then there have been some research reports that have come out recently that you may have seen that are fairly bullish on the prospect for NGL.

So given the fact that natural gas prices are so low relative to oil, kind of at historical lows in terms of that relationship, it makes ethane and ethylene very competitive with alternatives like naphtha and the heavy – to the feed stocks.

And so there is capacity or ability for the petro chem plants to switch from processing naphtha to processing ethane and so that’s another plus I think. So again kind of a long answer, but our view is that pretty positive for liquids, not so much on natural gas prices as we go on to next year though.

Lasan Johong

I see. And so what you’re saying is given that there is a $2 bump in gas equivalent prices for liquids drilling, you don’t see this having any affect on pullback in gas drilling going forward.

Pat Reddy

No, I think as we look at it, to get a 100,000 barrels of ethane – barrels per day you need about 2 Bcf a day of wet gas production thinking about the Marcellus and the sizing of the line that we’re talking about building. And as you know while the producers have been pretty optimistic about how quickly production will ramp up in the Marcellus, actually we’ve seen it coming on more slowly. So we don’t see additional NGL swamping demand.

Lasan Johong

Understood. Now, you mentioned previously that industrial demand for nat gas seems to be picking up. Can you give us kind of some magnitudes or percentage increases?

Pat Reddy

Well, actually that was specifically in the context of our Canadian distribution Union Gas. And when you think about the contribution to their EBIT from that, let me give you kind of an order of magnitude. On year-to-date, it’s been about $3 million of EBIT through the third quarter, so that’s kind of helped in part to offset the core market decline which was weather related in our first quarter.

Lasan Johong

And are you seeing in Union Gas, you said – I think you said also that you’re seeing some evidence of residential demand picking up, but is that weather adjusted or not weather adjusted?

Pat Reddy

We’re actually increasing our customer base at a little bit more than 1% per year, which is probably at or above the average per mature distribution companies. But we do continue to see some residential customer growth there.

Lasan Johong

Excellent. Thank you so much.

Pat Reddy

You’re welcome.

Roni Cappadonna

All right, I believe we have another question on the line.

Operator

Your next question comes from the line of Mark Reichman.

Mark Reichman

Good morning. I was just wondering if you could talk a little bit more about the Marcellus Ethane Pipeline System project. How you benchmark that against some of the competing projects out there, and just kind of a maybe a timeline or the milestones that turned this into a definitive agreement and getting into service?

Pat Reddy

Okay. Well, that’s a great question. There are other alternatives out there that are in various phases of planning and execution. And I could be wrong about this, but to my knowledge, I don’t think any other projects have actually entered into the phase of having contracts with producers.

But we talked about our joint venture with El Paso it’s a 50-50 partnership. And we will be contributing about a 100 miles of right of way in Pennsylvania and Ohio, existing right of way that reduces the need for Greenfield construction. El Paso would contribute about 850 plus miles of existing pipeline and it would involve some reversal of flow on Tennessee gas pipe. And then about 200 miles of Greenfield construction pipe in compression in stages, a vaporization facility, a liquefaction facility and then a Southern leg which would be the liquid pipeline down to the Gulf. And we’re looking at where that would interconnect probably Mont Belvieu and on into Louisiana as well.

So we haven’t talked about the capital investment. That’s still – it’s still early days and we’re developing those estimates before we can share them with the marketplace and prospective shippers. We’re looking at volumes of about 60,000 barrels of ethane only per day and with an in-service date kind of in the 2013, 2014 timeframe, which is when we think – I mean that’s our best guess of when a significant number of producers will need that kind of takeaway capacity where, for example, our and others ability to blend kind of hits the wall. And so that’s about as specific as I can be at this point.

Mark Reichman

Okay, thank you.

Operator

At this time, there are no further question.

Roni Cappadonna

We have another question here, Pat.

Pat Reddy

Okay.

Unidentified Analyst

Can you tell us your plans for refining the Texas Eastern maturity that’s coming up?

Pat Reddy

We do have a $300 million maturity at Texas Eastern. And as we’ve talked before we always have the option of financing either at Spectra Energy Capital or down at the operating company Texas Eastern. And I think our intention at this point is to make it a Texas Eastern issue as opposed to a Spectra Energy Capital issue.

Unidentified Analyst

[Inaudible]

Pat Reddy

I think, yes, I mean typically financing at the entity is the most straightforward thing to do for purposes of setting rates at the FDRC. Of course, as you know, others that finance at a higher level and again the corporate structure then push down or allocate the capital structure to their operating companies. And sometimes that results in a negotiation with customers and with the FERC staff about what the appropriate cap structure is. So – but yes, it is simpler and more straightforward to finance at the operating company.

Unidentified Analyst

I have two questions. In regard to the dividend which I think it’s supposed to be $1 a share, what do you see for future trends in the dividends that’s my one – first question.

Pat Reddy

Okay.

Unidentified Analyst

I’m a stockholder.

Pat Reddy

It’s an important question. We know how important the dividend is and in terms of our total return to shareholders. And I one thing I’d say about that is we’ve only been an independent company since 2007 and we did increase the dividend from the time we were spun out by 14% only to hit 2009 and which made us a little bit cautious about the economy and the pace of growth and so we did keep our dividend constant at $1.

What we would like to do quite simply is get to the point where we can resume increases in the dividend, keep our payout ratio at or below 65%, be able to grow the dividend in proportion to our earnings growth which we said in the next few years would be 8% to 10%. So it’s obviously a decision that our Board will make and we’ll be talking to the Board about dividend policy in December as we get ready to make our announcements about 2011 earnings guidance.

Unidentified Analyst

And one other separate question. In terms of the expansion in the Northeast and the pipeline, what will be – you’ll be doing in terms of the environment of getting nature back after you put your pipe in?

Pat Reddy

Well, we’re one of the older pipe – ironically to know we’ve just been independent for three or four years. Our assets go way back to the 1940s and even before, you may know that Texas Eastern started as an oil pipeline to move oil to the Northeastern in World War II to avoid U-boats and then was converted to gas after. And I say that because we’ve been pioneers and innovators in the business in terms of maintenance of our systems, we’ve invented some tools that allow us to look inside the pipeline and make sure we don’t have corrosion and that kind of thing. So I think we’ve been kind of out in front on that for a long time.

But having said that, there have been some pretty high-profile incidents this year not just BP, but most recently the San Bruno incident in San Francisco with a pipeline explosion and the tragic loss of lives and the property. We can’t say that that will never happen. In fact 90% to 95% of the time when there is an incident like that it’s a result of third-party damage where a contractor takes a back hoe and doesn’t call you to say they’re going to be working in the area next to your pipeline. So that kind of thing can happen.

But I think when you think about the various forms of energy, natural gas is much cleaner than coal and oil. We have a very safe record as an industry. We’re going to an awful lot in terms of communicating with the communities where the new pipe would go through, we’re doing it right now. And in fact, we’ve actually been shown a lot of flexibility I think in with the various cities and towns that we’re going through to sit down, review the route. And in some cases, parties will say, well, can you move it over a street. And we look at that feasibility of that and we have made a number of changes. So it’s only about a 16-mile pipeline, even though the project costs us about $800 million, a lot of it is for rights of away for environmental for permitting.

Roni Cappadonna

I might also add that we’ve been recognized I think for two years in a row as a Member of the Dow Jones Sustainability Index, which recognizes not only our environmental efforts but everything else that we do to on a sustainable basis as well as being a Member of the Carbon Disclosure Group as well.

Pat Reddy

Elvira.

Elvira

Hi, good morning.

Pat Reddy

Good morning.

Elvira

I wanted to follow up on the re-contracting question. Specifically as over the next couple of years as you see more gas maybe flowing out of the Marcellus, how that could impact some of the re-contracting on your –?

Pat Reddy

Okay. Well that’s something that we give a lot of thought to and continue to think about the changing pattern of gas flows in North America, where is all these shale gas is going to go and how soon it’s going to get to market. And so I have several thoughts about that.

Our pipelines like Texas Eastern originate in the Gulf of Mexico and then go to the Northeast demand markets like New York and then even beyond up into Nova Scotia. And one of the things that I think our pipeline brings is a lot of supply diversity. You can – on Texas Eastern you can get gas from the Gulf of Mexico from the Permian, Mid-Continent LNG, you can get gas from the Rockies through our interconnection with the REX pipeline, we can bring gas down from Canada on our system. And so if you’re a utility in the Northeast, I think you get a lot of supply diversity.

And the truth is that our portion of the distribution companies build a pipeline portion is relatively small. The lion share really is gas cost to commodity. And our costs are passed through typically for distribution companies in their rates. And so we haven’t seen and really don’t expect to see a lot of pressure there to turn that capacity.

The other thing you probably know is the way our rates are set. If you want to take just Marcellus gas that comes in kind of in the top third of our Texas Eastern system, you would have to turn back all of your capacity on Texas Eastern, all three zones, and then bid for capacity just on the Northern tier, I think it’s Zone M3. And then we do a present value calculation of somebody else bids for that same capacity and bids a higher amount you might wind up with no capacity on our system.

And so again the other thing about our pipes is that we’ve been careful to make sure that we serve end-used markets, we get behind the city gate and serve actual customers like distribution companies. Yes, we do have a percentage of marketers on our system, but our primary customers are industrial or utilities, and I think they value the diversity of supply that we bring. And we still think even with Marcellus gas that 10 years from now at least 30% of the gas supply is going to come from the Gulf and come to market. Other questions?

Roni Cappadonna

All right, with that, we thank you very much for joining us today.

Pat Reddy

Thank you.

Operator

This concludes today’s call. You may now disconnect.

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