Enbridge Inc. (ENB) Q2 2011 Earnings Report, Transcript and Summary

Good morning. My name is May, and I will be your conference operator today. At this time, I would like to welcome everyone to the Spectra Energy Quarterly Earnings Call. [Operator Instructions] Thank you. I will now turn the conference over to Mr. Arensdorf. Sir, you may begin the conference.

Thanks, May, and good morning, everyone. Welcome to Spectra Energy's Second Quarter 2011 Earnings Review. We are very pleased that you've joined us today. Leading our discussion will be Greg Ebel, our President and Chief Executive Officer; and Pat Reddy, our Chief Financial Officer. Both Greg and Pat will discuss our quarterly results and provide more color around our strategic plans to enhance the value Spectra Energy delivers to its shareholders. We'll then open the lines for your questions. Before we begin, let me take a moment to remind you that some of the things we will discuss today concern future company performance and include forward-looking statements within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements. You should refer to the additional information contained in Spectra Energy's Form 10-K and in our other SEC filings, concerning factors that could cause these results to be different from those contemplated in today's discussion. In addition, today's discussion includes certain non-GAAP financial measures as defined by SEC Reg G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our Investor Relations website at spectraenergy.com. With that, I'll turn the call over to Greg.

Thanks, John, and good morning, everybody. As I'm sure you've seen from our earnings release this morning, Spectra Energy delivered a second quarter ongoing earnings of $275 million or $0.42 per share, up an impressive 56% from our second quarter 2010 results. Our second quarter performance is nicely ahead of the curve, which we're pleased about, and we've got still 2 quarters to go including the important fourth quarter. But borrowing some macroeconomic calamity, we fully expect to exceed our stated $1.65 earnings per share target for 2011. The key earnings drivers for the quarter included a strong performance from all of our business segments, from both an operational and expansion growth perspective. Favorable commodity prices are also playing out nicely for our DCP and Empress assets with a positive outlook for the remainder of the year. And, of course, we realized the benefits of a much stronger Canadian dollar. However, commodity prices and FX only accounted for about 2/3 of our earnings growth for the quarter so perhaps, more importantly, roughly 1/3 of the growth was achieved through successfully executing on expansion projects. Those projects continue to meet the needs of customers and deliver strong earnings to investors. Those were our key drivers for the quarter, but we're also looking beyond the quarter's reach, ensuring that we've got a strong platform for delivering consistent, attractive value and growth for investors. Throughout our discussion today, you'll hear us touch on the strategic opportunities we're pursuing to ensure that we are indeed well positioned in the years ahead. A key to our forward positioning is a very deliberate and diverse capital expansion program. We're making strategic investments to expand our footprint, connect customers and markets with supply and create critically-needed energy infrastructure across North America. So here are some of the projects fueling are our growth, beginning with those recently placed in the service. We placed the Hot Springs Lateral into service in June and you'll recall, this pipeline will supply natural gas to the 620-megawatt KGen Hot Springs power plant in Arkansas. Our Fourth Cavern at our Moss Bluff storage facility begun producing revenues during the quarter and will provide an incremental 6.5 Bcf of capacity, increasing that facility's total working capacity to more than 21 Bcf. And during last quarter's call, we mentioned and you’ll recall, that both Gulfstream V and the Bissette Pipeline in British Columbia went into service in April. Importantly, all 4 projects came into service at or below our budget. Other projects on the horizon and well underway for 2011 include phase II of the TIME III project -- sorry, Phase II of the TEMAX/TIME III project, which is close to completion. And the TEMAX/TIME III expansion project links Rocky Mountains and natural gas supplies with customers in the Northeast, where we expect to see continued natural gas demand growth. We began receiving full revenue from the TEMAX project in November 2010, as you might recall. This year's additions, expand the project's physical scope and provide customers with increased flexibility. The Dawson Processing Plant in the Montney region of British Columbia is progressing well. And as planned, we expect Phase I to come into service later this year with Phase II to follow in early 2013 or, potentially, even late 2012, given the progress that we've seen so far. We're in the final stages of construction on our Northeast Tennessee or NET project and we'll complete that project in September. NET will utilize our East Tennessee system to move gas from the Appalachian supply base into a new 880-megawatt TVA power plant. It's a good example of some of the power conversion opportunities we've been talking about with you. Opportunities that we think we're ideally suited to serve. So good progress on our 2011 projects and looking ahead, we've got several other significant projects within service dates beyond 2011. Our New Jersey-New York project is proceeding. In late June, we received FERC's notice of schedule for the project's environmental review and in that FERC indicated issuing the final environmental impact statement in late January 2012. We would expect the FERC certificate to follow shortly thereafter. Although this is a little later than we originally anticipated, we're pleased to have greater clarity on the regulatory timing for this project, and we remained on track to safely place the project into service in late 2013. Our large-scale Fort Nelson Expansion continues within Canada's Horn River Basin. We're well on-track to complete the Fort Nelson North Processing Facility during the first half of 2012. And upon completion of this project, Spectra Energy will have more than 1.2 billion cubic feet per day of raw gas processing capacity and associated gathering pipeline in the Fort Nelson area, securing our leading position in the basin. And of course, all of our Fort Nelson contracts are underpinned by fixed-fee, take-or-pay contracts. In addition to the project I just discussed, which we fund from Spectra Energy's balance sheet, our Field Services segment, DCP Midstream, is pursuing a number of significant projects, which they will fund using their own strong balance sheet. We now expect to see a considerable ramp up in DCP's investment opportunities fueled by its ability to fully leverage its strong existing asset footprint in regions with growing gas and liquids production. DC [DCP] Midstream has its own slate of growth projects to the tune of $700 million to $800 million a year for the next several years. Quite a leap from the $200 million to $300 million annual investment it has averaged over the last several years. And as I mentioned, DCP Midstream's capital plan will be self-funded. DCP Midstream is continuing to expand its processing capacity in liquids-rich basins such as the Denver-Julesberg, the DJ Basin, the Permian and the Eagle Ford. And as you've heard recently, these basins are now ramping up volumes which bode well for DCP with its large and expanding asset footprint in the areas. In May, DCP Midstream completed the new $150 million cubic feet per day processing plant at its newborn facility in the DJ. Also in May, DCP announced the addition of a new 110 million cubic feet per day in LaSalle plant in the DJ basin, which will be in service in mid-2013. These new plants augment DCP's prominent position in the basin, and we expect there'll be other expansion projects as producers continue to drill in the DJ and Niobrara. DCP Midstream is the largest gatherer and processor in the DJ, and the business continues to invest capital to accommodate growing producer demand in this area, as well as in the Eagle Ford and the Permian regions. While DCP had a slow start to its volume growth early in the year, mainly due to weather, it's now seeing an increase in both wellhead volumes and NGL production across its portfolio. As an example, DCP is benefiting from this increase in volumes in Eagle Ford, where it's continuing to sign new contracts as production volumes build. Construction has begun on the previously announced 200 million cubic feet a day Eagle plant, which will be in service during the second half of 2012. And also during the quarter, DCP Midstream announced the acquisition of the Seaway pipeline from ConocoPhillips which will provide the backbone for DCP Southern Hills pipeline. DCP expects to close on the acquisition during the last quarter of the year, and with some added construction to close the gap between Conway, Kansas and Mont Belvieu, the pipeline will be in service by mid-2013. Upon completion, the total project cost will be approximately $750 million to $850 million, including that initial acquisition cost. Southern Hills' 150,000 barrel per day capacity will be utilized to transport DCP's owned or controlled volumes in the mid-continent and DJ basin, along with volumes from other shippers. And when completed, Southern Hills will substantially reduce the bottleneck at Connolly [ph] , allowing liquids to more easily reach the premium-priced Mont Belvieu markets. DCP is also making great strides on its Sandhills Pipeline project and we see moving forward with this NGL pipeline that will connect the Permian basin and Eagle Ford to Mont Belvieu. In addition to the volumes that it owns and controls, DCP Midstream has entered into agreements with targets and anchor shipper, preliminary agreements with Occidental Petroleum for key, right away, in the congested Mont Belvieu area, and preliminary agreements for the long term NGL gathering services with Chevron's majority owned West Texas LPG pipeline. DCP Midstream will present the project to its Board for approval later this month. As you'll note from my comments on both Southern Hills and Sandhills, DCP's ability to dedicate significant volumes it controls to underwrite these projects is a huge strategic advantage for the company. Let's turn now to some of the other growth opportunities we see on the horizon, regressively pursuing a number of projects on the drawing board, projects that move us forward and create quality earnings and growth on behalf of Spectra Energy's investors. Last quarter, we also addressed some of the broader fundamental shifts that are creating opportunities and growth potential. In British Columbia, we've seen producers refocus drilling activity from Horn River to the Montney region, which appears to have low refining and development costs and better overall economics. As a result of our existing large footprint in the Montney, we're actively pursuing a number of growth opportunities in this region. Also in British Columbia, the likelihood of LNG exports from Western Canada is increasing. A shift that Spectra Energy's ideally situated to support by connecting growing Horn River and Montney supplies to virtually any LNG facility developed on the west coast to British Columbia. Next, growth in the Marcellus region has created an opportunity, provided outlet for the liquids associated with rich gas, particularly ethane. The Marcellus Ethane Pipeline System or MEPS, as we call it, is a joint venture between Spectra Energy and El Paso, connecting this ethane supply with markets along the Gulf Coast. We continue to receive high levels of interest during the ongoing open season and are now in the progress of negotiating contracts with customers. And as we've indicated before, we'll expect to be able to share an announcement with you on that front before year end. Lastly, and a little further out in time, is the largely growing opportunity associated with power generators seeking to convert older coal and oil fuel plants to clean our more efficient natural gas and a more fully utilized existing natural gas facilities. Taking a look some of these opportunities, the ICF data on this chart shows a powerful trend of natural gas demand growth related to power generation expected to more than double by the end of the decade. Others have similar projections regarding this growth and demand so we expect to see many opportunities across our footprint as power generators consider their next steps. While much of this growth will come in the latter part of the decade, Spectra Energy intends to win its fair share of these opportunities. These range from increasing the utilization of the 55 gigawatts of gas generation already connected to our footprint, to serving new plants that will replace retiring coal or oil-fired generation. More than 100 gigawatts of coal or oil-fired generation sits within 30 miles of the U.S. pipeline that we own. And while not all of these facilities will be replaced, the opportunity is significant. In addition to these opportunities in the U.S., in the Ontario, government has announced its intention to convert some 3,500 megawatts of coal plants to natural gas-fired generation. All of these facilities are in Union Gas' service territory, and we expect to benefit from these conversions. The customer support services, storage capacity and operational flexibility of Spectra's assets are attractive to power generators across North America, and we're going to continue pursuing our efforts to be the pipeline of choice to serve this growing gas-fired power demand. So as you can see, Spectra Energy's projects in execution, combined with the tremendous potential of growing natural gas demand and deployment, support our goal of investing at least $5 million in growth projects between 2011 and '15. And DCP Midstream has experienced a historic levels of growth, which will support its own expansion opportunities for more than $3 billion over the next 5 years. So, with a great second quarter and we're well positioned for a strong second half of the year and we're equally focused on the future, well beyond 2011, to ensure a strong platform for delivering consistent and sustainable value and earnings growth to you, our investors. With that, let me turn things over to Pat, who will walk you through our financial results for the quarter in more detail

Well, thank you, Greg, and good morning. Earlier today, we reported second quarter 2011 ongoing earnings of $275 million or $0.42 per share, compared with $174 million or $0.27 per share in the second quarter of 2010. As Greg mentioned, the 56% year-over-year increase in earnings per share reflects the progress we've made on executing growth projects, improved commodity prices and a more favorable Canadian exchange rate. In addition to delivering strong earnings for the quarter, we continue to benefit from our healthy financial position. During the quarter, Union Gas issued $300 million of 30-year Canadian debt, at a company record low coupon rate of below 5%. And following receipt of its investment grade credit rating, our master limited partnership, Spectra Energy Partners, issued $500 million of term debt and about $215 million of equity. These proceeds were used to pay down SEP term loans on June 30, and to fund the Big Sandy acquisition on July 1. We expect SEP to continue to pursue organic growth and acquisition opportunities to help grow the entire Spectra Energy enterprise to its low-cost, tax efficient financing structure. And as you would expect with the growth we're experiencing, we're seeing significant increases in both EBIT and EBITDA, which helps fund our future growth CapEx program, so let's take a quick look at our EBITDA by business segment. Ongoing EBITDA for the quarter was $816 million compared with $657 million in the second quarter of 2010, a 24% increase year-over-year. Before we leave this Slide, it's worth highlighting, that with the level of increased cash flow, coupled with the benefits of bonus depreciation, we are now able to fund more than half of our expansion CapEx through internally generated funds, and that's after fully funding our dividend and maintenance CapEx. Said another way, our balance sheet continues to strengthen with the increased cash generated from our capital expansion program. Let's turn now to our performance by business segment, beginning with U.S. Transmission, which reported second quarter 2011 EBIT of $243 million, compared with $223 million in the second quarter of 2010. The key drivers behind this 9% increase are expansion projects placed into service during the fourth quarter of 2010 including TEMAX/TIME III and Algonquin east to west. Now, let's move on to Distribution. Distribution reported second quarter 2011 EBIT of $88 million, compared with $73 million in the prior-year quarter. This 21% improvement is mainly attributable to higher customer usage, due to colder weather, growth in the number of residential customers and increased in revenues from short-term transportation services, and a stronger Canadian dollar. A significant contributor to Distribution's quarter-over-quarter increase relates to weather. In the second quarter of 2011, we saw a return to more normal weather following an abnormally warm second quarter in 2010. And the effect of that change, coupled with the growth in residential customers, was about $8 million for the 2011 quarter. Let me turn now to Western Canada Transmission and Processing. That segment reported second quarter 2011 EBIT of $113 million, compared with $69 million in the second quarter of 2010 or a 64% increase. The segment benefited from improved results in the base gathering and processing business, mainly driven by expansions in the Horn River area, British Columbia placed into service in 2010. In addition, our Empress natural gas liquids business continues to perform beyond initial expectations laid out in our financial plan for the year and performs significantly better than in the second quarter of 2010. You will recall that the 2010 plant turnaround, not only net higher cost during last year's second quarter, but also led to reduced NGL sales volumes. The Western Canada segment also benefited from the effects of the stronger Canadian dollar. Let's turn now to Field Services. Field Services reported second quarter 2011 EBIT of $138 million, compared with $58 million in the 2010 quarter. This 138% increase in earnings was due mainly to higher commodity prices during the second quarter of 2011. During the quarter, in-shale prices averaged $1.24 per gallon versus $0.91 per gallon in the second quarter of last year. NYMEX natural gas averaged about $4.31 versus $4.09 last year and crude oil average approximately $103 per barrel compared with $78 last year. DCP Midstream paid distributions of $62 million to Spectra Energy in the second quarter of 2011. Our year-to-date distributions from DCP currently totaled $270 million including a distribution receives in July. We expect to receive a total at least $350 million in distributions in 2011. Now, let me turn to additional items for the quarter. Our Other category reported net costs of $29 million in the second quarter of 2011 compared with net costs of $16 million in last year's quarter, reflecting higher captive insurance reserves. Year-to-date, our other expenses are in line with our financial plan. Interest expense was $159 million, compared with $158 million in the second quarter of 2010. The second quarter's reported effective tax rate was 29.6%, compared with 28.5% last year. The favorable Canadian currency exchange rate increased second quarter 2011 after-tax earnings by about $6 million. At the end of the second quarter, our debt to total capitalization ratio stood at about 54% and that's down from 56% at year end. As I mentioned earlier, with the increase in our EBIT and EBITDA versus last year, we expect to fund our CapEx program through a combination of internally generated funds and debt, while staying within our targeted 55% to 60% range per leverage. And at the quarter's close, we had total capacity under our credit facilities of $2.8 billion and available liquidity of $2.7 billion, which included cash of about $500 million. On July 1, we used about $400 million of cash to fund the Big Sandy Pipeline acquisition. So that's an overview of our second quarter results, which are nicely ahead of our expectations. I don't think there's a peer company, today, more ideally positioned to lead and prosper in the natural gas energy infrastructure sector. We feel very good about where we are today and where we’re headed for the balance of the year. Our financial position and our corporate structure allow us to execute our 2011 financial and business plans and keep us on track to deliver the results investors expect for us. We set our 2011 EPS target at $1.65, and as Greg just mentioned, we fully expect to exceed that target this year. So when considering Spectra Energy as a whole, investors can expect to receive an attractive dividend yield and consistent EPS growth, generating an impressive total shareholder return. We think that's a compelling value proposition and we will continue to deliver value and growth to our investors, both this year and well into the future. So with that, we'll open the lines and we'll entertain your questions.

[Operator Instructions] And your first question comes from the line of Stephen Maresca.

I wanted -- a couple questions on the opportunities at DCP. First on Sandhills, can you talk about where and what the next steps are? Where you stand on commitments and sort of how we should think about this ramp-up in volumes from an initial 200 for the possible 350?

Yes. I mean, I think, the initial look you should kind of think about the 200, we have -- confident that DCP management's is going to bring a very positive case to the Board which, as you know, is made up of Conoco and Spectra later this month. And I think from what I've seen, we feel pretty good about moving forward. I don't think there's any doubt we're going to forward. We got to go through corporate approvals. When we go to 350,000 barrels, I think, that's all about how the growth kind of moves forward over the longer term. The nice thing, again, about this is that, we've got well over, call it 2/3, of that initial volume under our control that we can underwrite the pipeline on. And as I said, I think that's a huge strategic advantage. So at this point in time, Stephen, I can't see any reason why we're not full steam ahead and get this pipeline in service, and given that we're now seeing volumes in places like the Eagle Ford, above what we have thought at this point in time in the year. That kind of acceleration goes on. Who knows? Maybe we can get the growth maybe even faster than we had thought up to that 350,000.

Okay. And then on Southern Hills, is that falling right now? The 150 barrels a day of new capacity or is that what will come on in 2013?

Well, that's what will come on because right now it's not an NGL pipeline, right? So when we take it over, we'll have to do some construction and then obviously, make some changes from an operating perspective. So that'll be incremental. And that's not all reliant on incremental volumes coming out of those regions, because remember, right now, DCP would be shipping on other pipelines. So as pipelines, where we've made commitments, those commitments, those contracts end, we would move those over to Southern Hills.

Okay. And then my final question is shifting up to Western Canada. You talked about future shifting, I think, you said from the Horn River to Montney and obviously, the LNG export possibility seems to be increasing. Can you remind what, from your standpoint, what you would need to do and how directly impact will it be to you guys?

Well, when we look at this, in early days and obviously competitive, but there's nobody with a pipeline going north to south closer to the coasts than Spectra Energy, that's for sure. So we would build the lateral from the northern part of the West Coast pipeline indicate them at or wherever the facility would be. Pretty tough territory up there, again, early days but that's probably -- call it $1.5 billion, $2 billion worth of an opportunity. What has to happen, of course, is a couple of things: one, you have to have an export licensed by the customers we would serve in other words, producers; two, they have to get their approvals to build the plan or feel very confident they can build a plan; and then it would be, at that point in time, that they would think about making commitments to a pipeline. So we are probably last in the train trail, if you will, in terms of what they've got to do, but nonetheless, we're just very optimistic and obviously, we'll be very aggressively, we've been in that region for a very long time. We have almost 1,000 people that work for us in British Columbia, and given our position and the ability to, not only transport gas but, also process and gather gas in that region, we think some really big leg up for us.

And your next question comes from the line of Monroe Helm.

Just a quick question on what the capital cost would be for the both Sandhills project and the Southern Hills project?

Monroe, we haven't put out those numbers yet to any full extent, only -- it's obviously, a pretty competitive environment. I did say Southern Hill is kind of be in the $750 million to $850 million range, including the acquisition. I think it's probably fair for me to say Sandhills, depending on how we build that out, call it in $1 billion range, but I wouldn't get more specific at this point in time. Once we get approved, ready to go and little further down the trail, I can be more specific at that time.

Okay. If I heard correctly, you think there's a good chance the Board's going to approve the Sand Hills project this month, is that what you said?

That is correct.

Okay. And you got their commitment for 2/3 the initial volumes, pretty much have that in hand?

Correct.

Your next question comes the line of Ted Durbin.

First question, Conoco obviously has announced their restructuring. They haven't really said what they're going to do with their stake with DCP, have they given you any indication? And then can you remind us, what is your option if they decided to sell it? And if you did take 100% control, would change your policy at all on how you operate it?

Well, first of all, I would say that we love the partnership with Conoco, and for many, if there are, indication I get from them, they like the partnership as well. So I would expect that one way, whether it goes upstream or downstream, my personal view is that they'd probably hold the asset, and I think that would be viable for everybody and it would actually make DCP a larger entity within Conoco, again, whether it's upstream or downstream. And I think, I can make strong cases to go either way but that's obviously, a Conoco decision, if they decide to sell. You're right, we do have a welfare again, I'm not expecting that, but that's something we'd obviously look at, that would change the structure and maybe you do some things differently, if that happened. But again, I don't expect that to be the case. As I outlined, there are great growth prospects for DCP Midstream and given the self-funded nature of DCP Midstream when you combine in DPM, I like the business, I like Conoco and if there's an opportunity down the road to change that obviously, it's something we'd look at it.

Okay. And then just going back to the Southern Hills pipeline, I guess I'm just thinking more about the differentials we have between Conway and Belvieu, very wide right now. Do you see those narrowing at all before this pipeline comes in service? I mean, we're looking at the next couple of years of having pretty wide differentials. And then just one for Southern Hills itself, would you go ahead there, as well, with just DCP volumes, or would you need third party volumes to actually start that up?

No, I think we're pretty comfortable with -- that it's a go. We bought the asset -- we made that decision when we bought the asset, Ted. So and I think the advantage we have is being there now. And we feel confident that we've got enough volumes to move forward. With respect to the differentials, a bit of a mugs game. I think as pipeline infrastructure foreshadows the change in a bottleneck, like you're removing it, I wouldn't be surprised to see narrow a bit. But until you're actually flowing, who knows? I will say, if you look at the pet-chem industry in the United States, I mean look at May, June numbers, we're talking about 91%, 92% capacity utilization up from kind of mid-80s even a month before. You continue to see propane supplies well below 10%, 20% below 5-year inventories. We've continued to see good exports. So I don't see the market in much of that all going on in the Gulf Coast changing. And as such, I think that bottleneck -- there may be even more opportunities to build. So I don't see the differential disappearing entirely, that's for darn sure.

Okay, that's helpful. And then, just maybe talk a little bit more about the Bobcat expansion. Are you sort of moving faster or maybe moving slower given that we have a pretty weak market there on the expansion project?

Yes, I see most of our build was kind of in the '14, '15 or '16 time frame, so I wouldn't say we're moving any slower or faster. You’re right, there's some weakness in storage prices given the way in which we contract, though. We have multiyear contracts, single year contracts, et cetera. So we're plus or minus 10% of where we thought we would be. Like you kind of maybe a little at 10% lower than what might be -- have seen in our regular portfolio from a storage perspective. But it does not change the overall view we have on storage, the need for that from a power perspective, the need for that both in the market area and in the supplier area, so we're still driving forward Bobcat, that's for sure.

Your next question comes from the line of Craig Shere.

Couple of quick ones. On MEPS, can you comment on the level of interest you're receiving from petrochems relative to producers and then if I can kind of dovetail on Ted's question. A couple of peers, this morning, have kind of put out some rough performance on gas storage operations, you kind of alluded to it but right where noted your contract portfolio. We heard of some more current contracting rates multiyear running south to, say, $0.14 per mcf month, I'm just wondering if you can comment if you're seeing similar figures in the current market and if you can advise what remaining average contract durations exist on the operating caverns of South Hill, Market Hub and Bobcat.

Well, let's sort of go in a reverse order to make sure I remember all your questions. So I'd say on the storage front, our typical contract life remains in that 2 to 3 year range. And as such, Craig, we're not being buffed it as bad as perhaps, many others are by, who have kind of stop with short-term contracts. But I wouldn't disagree with there's no doubt that you're seeing considerably lower storage prices today, but as I mentioned in Ted's comment, that in terms of our overall value in the storage side, you might see a 10% impact in terms of the overall portfolio, given the way that we do structure the contracts. And again, my view is, this is just a rebalancing of the gas market, its why we structure our contracts over multi-years, so that you don't end up having -- when you see a dramatic change in storage values over a short period, it really doesn't have a material impact on Spectra Energy. It's a long-term story is, I think, is the one we want to look at, and that we think is going to continue to be driven a lot by power demand and the need for deliverability, et cetera, across the system, which we think we can do when you tied into our pipes. You talked -- your first question was MEPS, petrochem and producers. I'm going to beg off, a little bit, I give it really -- what I will say is that yes, we have both petrochem and producer interest which is different than what we've seen historically, but given the -- let's face it, there's a dogfight for who's going to get this project and I like where we are, I like our partner, I like what we're doing but I'm not going to get into the some of our strategies and what we're seeing with the open season, Craig.

Okay. Since this is probably not going to be online, I think well as of 2014, and then maybe some needs earlier, do you think you can get firm contracted commitments even while a shorter-term bandage solution is put on?

Yes. And remember we've done a little bit of that, a lot of the pipelines by adjusting gas quality issues over the last 18 months which, as you know, is really a tough issue to work with the various different customers. And so, I would say, that is, at least, a little bit respect to Texas Eastern, that is the short-term band-aid solution. I think longer-term, yes. I think the guys are looking at, when I say the guys, producers, and the Dows of the world, they're looking at opportunities much further out than the short term and they're looking to make major capital investments and they will be looking to sign up long-term contracts. What I can also tell you is we're not going to build the pipe unless we do see that. That's been our mantra, and I think that's boded well for investors and El Paso would be on the same Page.

. Your next question comes from the line of Carl Kirst.

Just a couple quick follow-ups, I guess, from sort of the things that have been asked. Well really maybe one, with respect to DCP and generically, as we approach now the new project, Southern Hills, Sandhills, are the economics on, say for instance these pipelines in particular, are these more fee based? Are these more equity volumes? I'm trying to kind of get a better sense of, as we ramp and have more capital deployed at DCP, do we wind up kind of keeping the same commodity sensitivity, if you will, or are we migrating more towards fee-based? And as long as Conoco stays a partner, and presumably wants to focus on being liquids-rich, presumably they want that commodity sensitivity, so we're just trying to get a better understanding of, perhaps, the future economics of these projects.

Right, so if you look at that slide we put out, I think it was Slide 4 or 5, probably #5. Obviously, Mewbourn, LaSalle, Eagle, those plants are your more typical activities of DCP in higher-return type structures, if you will. But no doubt, the large capital expenditures at Southern Hills and Sandhills are much more fee-based, and so you would see those as less returns as what we've, maybe, historically seen. However, remember it's better than just your typical pipeline because as I mentioned, we do have some of our own volumes that will underwrite those, so you're being able to capture the differential, the basis differential there when you sell in the product, the end product at Mount Belvieu. And so you get a fee-based plus a kicker in being to attract the higher price from the better markets and higher-demand area in Mount Belvieu. So it's a bit of both, Carl. But ultimately, that would reduce the sensitivity but we're growing volumes fast and remember, DCP, I'm not sure if the market always recognized it, is a huge entity and so even a $700 million or $800 million a year to substantially change the structure or nature of the portfolio, would take several years of being -- to do that to make a big impact. Do you understand?

Absolutely. One micro-question, if I could. Actually, just turning to Canada and Empress. Even with the turnaround not being experienced here this year, I'm wondering kind of what you guys are seeing, say for instance, July third quarter here. We actually looked like flowed a good did through Empress' third quarter of 2010. And I didn't know if we were seeing, roughly, parody year-over-year or if we're actually seeing volumes that are 15% 20% down, I just didn't know if you have more of real-time data point there.

If you look at the inlet volumes at Empress they're up substantially from last year in the first half and in the second quarter. And there's no doubt we had a pretty cold winter, as you know, Carl, and that the important element or one of the key elements there is propane. Now as I mentioned, propane inventories are well below their 5-year average in North America. I would suggest, if you have any kind of a start to the winter, which I never underestimated Mother Nature, I think you could see continued nice performance there at Empress. First half was already pretty flat powerful, second half maybe not quite so powerful but we're hanging in there our own. And we seem to capture, more than others, given our ability the way in which we can process some of that gas.

Your next question comes from the line of Steven Wong [ph].

Quick question here of Southern Hills. Is there expansion potential beyond the 150 that you have mentioned?

Yes, a little bit but it's not to the same extent to when you're building a new pipe, like Sandhills, where you could go from 200 to 350 so we're not assuming that's a big upsize, Steven. That's why I said I think there is plenty of volume we just -- I think our metal strap is a faster metal strap, if you will, given that we're already flying a significant portion of pipe in the ground. But that's not something we're banking on at this point in time, but as I see with other of our infrastructure, just on the natural gas side, we're always able to find ways to add a little bit of compression, add some, but I wouldn't -- 150 should be the number you should think about from a longer-term perspective at this point.

And then, I think you mentioned that you have contract -- DCP has contract at roll-off. When does that happen and, I guess, that'll be before 2013? And who are the -- who's the main shipper you guys use today?

Well, the main shipper in that regard, with respect to Southern Hills, will be ONEOK. And those -- we are very fortunate that as volumes grow in those basins being served by Southern Hills, we have contracts running off from transportation we would have contracted 4 years ago. So that's a nice confluence of events, Steven, is that it really allow us to underline that pipeline .

And I have a question for Pat here, I guess. At the end of the year, what do you expect of the debt to cap to be?

We're at 54% now, and I would think 54%, 55% would be where we'd be at year end.

And then, so Greg, when we look out for the next year or 2 with all the projects that are -- it looks like it's definitely over a billion dollars a year for the next couple of years. Do you anticipate external equity needs right now?

No, I don't. A couple of figures: one, just the cash that we're generating from the projects that exist today and when we've -- we also give a little equity kickers when things happen at SEP overtime, so I sure don't need us or see us just getting any common equity from Spectra over the 3-year plan, if you will.

Your next question comes from Nathan Judge.

Just wanted to follow up on the North New Jersey-New York project. If you could just give us an update given some of the comments [indiscernible]

Yes. Well, I would say, as I said, the FERC's come out and that the FERC is the big approval. And that's a set for getting the final environmental certificate in late January and we'd expect the go forward certificate shortly thereafter. Jersey City is one city, in many, in that area. I think that we're addressing, virtually, all the concerns of the various cities there. Do I expect to get every person on side? No, but this will be one of it that, at least, the safest pipeline being built in the area. It's going to produce 5,000 jobs it's absolutely critical if the politicians in that area, the world are worried about what citizens are paying full for energy prices, Nathan. Just 2 weeks ago, Thursday, Friday, when it was hot in Jersey and New York, by our calculations, those citizens paid $35 million more in that 24, 36 hour period for electricity just because there was not additional pipeline to bring gas into that region. So I think the economics, I think the jobs, I think the safety that we are putting in place are going to see this pipeline move forward and we'll get it in service in November 2013.

And just as far as the Governor's Office, I think there has been some comments in the past about questions about the pipeline and safety is addressed. And obviously, you've addressed some of those questions but do you expect to have any comments from the Governor's Office anytime soon?

Well, I wouldn't be typical. I think maybe what you should look at is the master energy plan put out by New Jersey, which is obviously, put forward on behalf of the Governor. And it is very strong natural gas-centric, very strong on the need for new and expanded pipelines and gas-fired generation. All of which would suggest a very positive attitude towards pipelines like New Jersey-New York. Also, I think 5,000 jobs in that region of the world is a pretty powerful source of support as well.

Sure. And then just as a follow on to the TEAM opportunities. I mean, if indeed, this does go forward as you anticipate, when should we hear more about TEAM and potential there and can you kind of quantify the size of that?

Yes. I think, that's TEAM is expected to come into -- TEAM 2012 is expected to come into service late next year, so that's moving forward, Nathan.

I'm sorry, just to clarify. I just mean the -- you talked about your growth opportunities and then you mentioned TEAM and clearly, there's some desire for new pipeline.

Yes. Well I think, you're going to continue to hear about those, as we move forward. Nathan, I would expect that you'll see -- we'll continue and announce that as we go forward here. We're looking at TEAM 2013, is there a project there. We've talked about some 2013, 2014 projects. I think as you know, it typically takes us 18 months, 2 years so as we get to the end of this year and starting into next year, I think you'll start hearing about some of those additional opportunity.

Yes. When I look at it, if I add up all those opportunities' potential, you're talking about $7 billion or $8 million maybe up to $9 billion of opportunities we see out there from everything, the northeast and the southeast. And then you throw on the DCP opportunities, it is not a stretch for me to see us facing up to $10 billion of opportunities on a combined basis between DCP and Spectra over the next, say, 5 years or so. Will we get all those? No, but we're going to get more than our fair share and at least, call it, at least $0.5 billion of that will be in the northeast.

That's very helpful. And just to follow-up, if you could just remind us on your view of mergers and acquisitions, given some of the activities of late.

Well as you know, we have picked up assets each year more in that kind of a $500 million to $2 billion range. There's no doubt that the acquisition market is frappy. And my view is when we look at acquisitions, we are largely looking, as we've always stated, by using the MLP, particularly for assets of those size, one and those are highly accretive, both to the MLP and really highly accretive Spectra Energy; and two, I'm really thankful that we've got $10 billion of opportunities to go after because I don't think there's any doubt while it takes a little bit longer, you can build cheaper than you can buy in this market. So, if we had our drivers, it would it be to build. Where we would look to acquire is when if we look at a significant footprint expansion opportunities for us. But those aren't part of our plan or needed for us to be able to achieve the type of earnings growth and shareholder return we've been discussing.

Can I just put the equation and just that, can you answer the questions about potential being the seller?

Us, being a seller? Well, my view is we keep growing the company the way we're growing and get the returns that we're seeing. That's never a concern to me. I guess someone has going to have to pay a very high price. I mean our focus expanding the business and growing it and I don't worry at all that being a seller, frankly.

Your next question comes from the line of Becca Followill.

On Southern Hills, you may have said this, but how much is your own NGLs that you're going to put on the line? You said how many capacities you're going to take?

Think about in the 50% maybe up to 65%, but 50% to 65% of that capacity would be us.

Okay. And then on the MEPS system, realizing that's going to be end of the year before we get something it has. Can you tell us whether or not that Utica results that have come out recently have changed people's perspective on signing up long-term contracts? Has there been a hesitancy, then we know that there's been liquids there for a while for people to sign up for contracts? Does that change anything?

No, I don't think so. I think the bigger issue of people signing up is the general economic uncertainty. And probably, there's no doubt you throw in a little bit of Utica, you throw in a little bit of our concerns about Pennsylvania, you throw in the fact that we've created a short-term band-aid, if you will, from pipeline spec perspective or gas quality spec perspective. And that's probably created a little bit of a delay. But that's a short-term issue, Becca. I think from a longer-term perspective, there is no other logical solution than a pipeline to the Gulf, and I think the market's recognizing that. It's just the timing in which that's going to happen.

Your next question comes from the line of Ross Payne.

Greg, quick question. What's your -- what do you think the timing on Kitimat is going to look like in terms of that facility potentially getting up and running?

I think it's mid-decade, as I said, they've got to get customers, they've got to get an export license, they got to get the okay to build a facility and then get on the pipes. So I don't say you can't do it before mid-decade. Although, sometimes things go more rapidly, but that would be my view. I mean, that's only 3 or 4 years, or 4 years away, Ross. I don't think that's overly aggressive. And I think that the producers are being very thoughtful about how to do this and you got many parties involved now from Petronas to the shales of the world, and of course, the Incanas and Apaches, they've all announced possibility. So I think they're being thoughtful, making sure that they build this right, build it to the right size and sure are going to take customer risk. On the opposite side, things like the unfortunate situation in Japan, put a greater intensity on customers, end-user customers of this gas also want to move faster so maybe that helps. But I'm still thinking mid-decade.

Okay. And in terms of pricing for LNG off at West Coast, is that going to be highly correlated to crude, in your opinion? Or is that the correlation breaking down somewhat?

No, it's still there. I think that's the consideration, you have to be able to, and this would be the producers, you have to be able to sign long-term contracts and equivalent crude price that makes the transportation impact negated, if you will. So you're probably still looking at, I don't know what their economics are, but you're probably still looking -- you need long term contracts equivalent to $90,000 oil from an international perspective.

And also Greg, any thoughts on, and I know you kind of have prodded a little bit on this earlier, but in terms of the COP's midstream. Any additional thoughts you might have on whether it goes upstream or downstream within that spend?

No. As I said, I think that's probably a better question for them. Either way, where it goes, I think we'll look forward to continue working with Conoco Phillips, if they decide to do that which, I've said, I would expect that, that would be the case. But I think that's a question from Mr. Mobba [ph] .

Your next question comes from the line of Faisel Khan.

It's Faisel from Citi. On your TETCO system or for that matter, your entire pipeline systems. I guess with the 55 gigawatts of gas price generation that you guys serve, how much of that capacity is under a long-term fixed contracts versus interruptible transportation agreement?

Only about 10% in the Northeast is under long term contracts. In the southeast, it's closer to 50%, I think.

Okay, got you. So what happens now, if this utilization for gas regeneration kind of continues to ramp up? What are the conversations been like with your customers in terms of signing up for firm capacity?

Well, it's a lot more constructive because obviously, if you're a producer and you get called upon, you have to have availability of gas. And as I think, you will have seen how it's been in New York, we've seen all-time peaks. Folks are worried they're going to be cut short. So the issue is one of signing up longer-term contracts and/or storage, and I think storage is equally, guys. And that's maybe more common about the merchant players, Faisel. On the utilities side, I think it's much more of, "Look this is a flow through cost from a utility perspective. There's no reason to take the chance that you haven't got capacity. And as such, what can we do to make sure that we've got longer-term capacity?" This is a big market, I don't want to overestimate the benefits that any pipeline can get cause there's always some capacity that's already there but it's mainly more about locking in longer-term contracts that really protects your base and then adding some additional incremental value through storage, which we think we've got an advantage off, given our storage facilities along our pipelines serving those gas generators.

But how long do you think it would take for these contracts, some of these interruptible contracts to kind of hider into longer-term, fixed-term sort of agreements? Is it still far away? Are we or do we see some sort of turn in the near future?

Well, I mean, in the Southeast, they give it you direct examples. I think right now, I mean, the Arkansas, the Hot Spring, that's an example of a merchant, if you will, KGen having us build the Lateral to them and obviously, that's a long-term contract. And then utility TVA building a very large lateral, so that's happening now. But I think this is 5 to 10 year type of process, which is why I said a little further out, this is the issue. And I don't think that's going to change. I think it's -- if you look at all the forecast in the last half of the decade, power demand, your gas utilization for power, really doubled. So if it was 1% or 2% kind of growth, you're going to see 2%, 4% type of growth. And that's where we going to see things really start to kick in because as I said, neither one of those parties wants to be short capacity. And I think the regulators are starting to see this, as well. So I see us picking up some of these laterals that we've got now but from a longer-term perspective, it's 5 years and beyond that this becomes really accelerated.

Okay. And just going back to the question that, I think, Carl has asked before. I think he was trying to figure out the contribution from Empress in the quarter. Do you guys have that? Or what's the EBIT contribution from Empress in the quarter?

Yes, we do have it for you.

Yes. For the quarter, the contribution was $20 million and for year-to-date it's $62 million.

So down quite a bit from the first quarter to the second quarter?

Yes, but that's what -- I think the bigger point, Faisel, is we've earned all plus, what we thought in the entire year, in the first 6 months.

You may remember, we've budgeted $56 million.

Yes. Ok, great. And then last question, on your Maritimes in Northeast system, have you seen a steady flow of gas from kind of the Canaport facility into your eminence, your budge in the Northeast system.

Yes. Actually, I haven't seen the summer numbers but the winter, throughout the year, those winter numbers remained very steady. I think, they're in the kind in the 300 a day range. Good summer flows on 12-2. I just don't have those numbers to give you, but obviously, given the heat and some of the backlog that we've talked about of infrastructure bottlenecks in the Northeast, you continue to see good flow on air times, which people have talked about. Not much in the way of LNG coming in. Well, I think, that's true relative to what we thought, say, in '07, Faisel. But in places like Canaport, you’re continuing to see those facilities be used nicely.

Operator, we're on our hour. We have time for one more question, please.

Your final question comes from the line of Andrew Gundlach.

A couple of quick follow-ups to questions that have been asked. On the Southern Hills, is the 35% to 50% third party volumes been either -- have verbally contracted in some way or you're just confident you can get them.

We're just confident we get them.

And would -- does Overland Pass then, become the key pipeline that takes the NGLs from which, I guess would be the Niobrara volumes into Southern Hills, is that the way to think about it?

In the Conway and then down?

That's correct.

Yes. Of course, we've just built the Wattenberg pipeline, that's going to feed it as well.

Okay. So it's Wattenberg and Overland basically, right?

Yes. I think that's a good way to look at it.

Okay. And the returns, you mentioned $750 million to $850 in the billion range for Sandhills. How do you think about the returns for these 2 projects? On an undelevered basis?

Yes. I think of them more, from a rocky perspective, more of as a fee-based pipeline type of return as opposed to a processing return. So you're more kind of a 10% type of returns, 10% to 12% right, type returns versus that 15% or 20% type returns we see across the rest of the DCP business.

I see. And that's because...

So you're not taking the commodity risk, it's largely fee-based.

Well, I guess I was thinking from a slightly different angle but maybe you answered the question earlier. Well, do you think the combination of an increase in Sterling which ONEOK has announced and this pipeline is enough to, in effect, eliminate that basis so that basis differential such that nobody will earn that, call it, $0.50 and $0.25 that's being earned today, is that how you think? And therefore it's fee-based, is that in effect what you're saying?

No, that's not what I'm saying. In fact, I don't think those to -- well, first of all, there's timing differences. I think we'll have ours built before the new Sterling pipeline, just given we've already got plant in the ground. But what I -- and I think what you're seeing in the Gulf course -- I mean, the Gulf Coast region, think about the announced increases by the various players, as I said the Dows and others, and the amount of incremental, potential incremental NGL demand that they're going to put on. I'm not sure this is enough and so, we'll have to see where it goes from here. But I think there is more than enough volume and capacity therefore, going to be needed on pipelines and producers are still going to be able to achieve that basis differential. Now whether some of it erodes, I mean, you'd expect some of it, but I have no doubt that you're going to see an upside from producers from a long-term perspective between Conveiw [Conway] and Mont Belvieu.

But so who will earn that basis differential, if it's fee-based?

Well, we'll get some of them. What I'm saying is there's a difference in our processing business, where you're taking your cut, if you will, your in-kind, we don't get all of that on the pipeline. We'll be able to attract some of that benefit and obviously, our own volumes but a lot of that's going to go back to the producer.

I understand. And encouraging that you're spending so much money at DCP. One last question on Conoco. This follows up on Ted's earlier question. Can you expand a little bit on how the ROFR actually works with Conoco; and #2, assuming that it would be up for sale and you're the obvious buyer for it, given your $10 billion of opportunities, that might require equity. Am I incorrect in thinking about it in that way? Or better question is how do you finance it if we should have it come up.

Well, it all that depends on price, that depends on how plan to structure the thing. Look, if you're thinking that DCP is worth $20 billion then obviously, that would be a major acquisition, that's a different part of the world, right? If you think DCP's worth a $1 billion, then I don't know why you would need equity. So that's a question I can't answer. With respect to -- I do think DCP is definitely undervalued in the current Spectra stock and Conoco, for that matter. But with respect to the ROFR, I mean, if they sold it outright, then it works like any other ROFR, we'd have a right of first refusal on a bona fide bid that they would get in. But as I said, you have to speak to them whether that's their intention, but I think they like the partnership, I know we like the partnership and the entity would be -- DCP would be a bigger proportion of their, whether upstream or downstream, and so I'm not sure why they'd want to go down that trail.

Operator, that's all the time we have this morning.

Okay, do you have any closing remarks?

I'd just like to thank everyone for joining us today. As always, if you have any additional questions feel free to call Roni Cappadonna or me. And with that, we'll close the call.