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

Thanks, Krista, and good morning, everyone. Welcome to Spectra Energy's Second Quarter 2012 Earnings Review. Thanks for joining us today. Leading today's 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 questions. But before we begin, let me take a moment to remind you that some of the things we will discuss today concerns 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 include 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 you've seen from our earnings release, Spectra Energy delivered second quarter ongoing results of $215 million or $0.33 per share. Like many in the sector, we felt the effects of weak commodity prices which were much lower than our original assumptions. Our Field Services segment experienced the most significant impact. However, lower propane prices also adversely affected our Empress plants in Western Canada. It was definitely a tough quarter for commodity prices. NGL prices dropped almost 40% from 2011. NYMEX natural gas average almost 50% lower and prices were weakened by a lower demand caused by petchem outages, slower economic conditions, record warm winter weather and exceptionally dry summer affecting crop drying expectations. Recently, we have seen an uptick in commodity prices off the low point about 6 weeks ago. But I think it's fair to say that it would take an extraordinary increase in NGL prices for the rest of the 2012 to be at the average level we projected at the begin of the year. Pat will provide more details around our commodity price expectations in just a few minutes but given the current and near-term commodity price environment, it's very unlikely we'll realize our $1.90 earnings per share target for 2012. Now that said, looking beyond the quarter to the longer-term, the NGL fundamentals remain very positive for our business. Crude oil remains expensive relative to NGLs, new demand sources on the petrochemical front are set to come into service mid-decade. The infrastructure bottlenecks that restrict our volumes and Conway pricing relative to Mont Belvieu should dissipate over the next 12 to 18 months. In addition, propane should benefit from new export facilities starting late this year and early next. And we'll then have to assume that the abnormally warm…

Well, thank you, Greg and good morning, all. As Greg mentioned, Spectra Energy reported ongoing second quarter earnings of $215 million or $0.33 per share, compared with $275 million or $0.42 per share in 2011. Ongoing EBITDA for the quarter was $674 million compared with $816 million last year. As we've noted before, our ability to generate solid levels of cash flow throughout general market and commodity cycles allows us to fund a substantial portion of expansion capital while continuing to maintain an investment grade balance sheet and consistently grow our dividend. Let's turn now to the business segments that generate that strong cash flow. First, U.S. Transmission reported second quarter 2012 EBIT of $237 million compared with $243 million last year. Quarterly EBIT reflects increased earnings from expansion projects, as expected. However, the benefit was more than offset by lower processing revenues and, as expected, lower storage revenues. Now let's move to Distribution. Distribution reported second quarter EBIT of $75 million compared with $88 million in 2011. The decrease is mainly due to a $5 million charge resulting from a negative regulatory decision affecting 2010 and 2011 storage revenues, and a weaker Canadian dollar. Turning now to Western Canada Transmission & Processing. That business reported second quarter EBIT of $94 million compared with $113 million in 2011. Contributing to second quarter results were additional earnings from the Horn River expansion projects, and lower expenses due to the lack of any processing plant turnarounds this quarter. The second quarter of 2011 reflected cost associated with the McMahon Plant turnaround. However, these gains were more than offset by losses at the Empress NGL plant, attributable mainly to lower NGL sales prices. For the second quarter, Empress realized an operating loss of $10 million and also recorded an $8 million noncash charge…

Okay, Krista, we're ready to take questions.

[Operator Instructions] Your first question comes from Craig Shere.

A couple of quick questions. First, is there any kind of -- even without recovery, which I would agree, seems inevitable specially for propane, is there any upside in Empress in so far as weak NGL prices might lead to falling processing premiums paid to producers?

Yes, that's right, Craig. And in fact we're seeing that now. The issue is that there's really -- nobody is taking on much in the way of volumes right now. As you know, you kind of contract in that business for 12 to 18 months, so you don't do it over the long-term. But yes, we've seen extraction premiums in that day market go as low as a couple of bucks, $2, $2.50 and as high as $7 or $8 which we've seen historically. So it's all over the map right now but I think you're right. Obviously with low propane prices, people aren't going to pay those type of extraction premiums. So we're not even out there in the day market buying that type of stuff unless we can sell it immediately at a profit -- that kind of thing. So these things do balance themselves out. You get a normal winter. You get some crop drying going on and some rationalization out there, I think things turn around again. So you're right, that's exactly what -- the first sign of that is declining extraction premiums.

Right. So the more recent results were kind of a double whammy of higher premiums paid and then after that happened, lower margins on the volumes coming in.

Again, right. So the gas season, as you know, is November to October. The propane season is kind of April to March. So you're going out there and you're signing up your contracts where you buy the gas, i.e. agree to pay an extraction premium and then you sell it in the -- that April, March period. So you get that time period there where if you see the kind of decline -- Conway prices going from $1.30 in December to $0.50 in July. That's the exposure you have, and as such, kind of extraordinary but that's what we've seen.

Right, appreciate the update there. One other question, you guys have had just stellar historic results with your creative growth projects. But honestly, we've had a couple of hiccups more recently. A lot outside of anyone's individual control but previously, we had announced the cost of runs at New Jersey-New York expansion. It sounds like that might be close to 11x EBITDA, and certainly Bobcat doesn't quite have the economics, at least for now, as originally envisioned when it was acquired and we still have some growth projects there. In aggregate, on a proportional basis, do you have a rough update on the expected economics of the projects under construction in aggregate?

Yes. They're in that 10% to 12% range that we've put out there. And I think if you took the aggregate projects, we're plus or minus 5% on CapEx. So you're right, I mean, the New Jersey - New York one is probably the biggest one. But you're gonna have some wins, you're going to have some losses. I feel good about where we are in things like TEAM 2012. But in aggregate, we're still very much in that 10% to 12% range. And as you know, through last year we read more like 14% on those returns. But again, yes, it's a challenging environment out there to put projects into service.

Understood. And on a proportional basis, you still feel you're in that 10% to 12% area?

Yes, sir.

[Operator Instructions] Your next question is from Chris Sighinolfi.

Just want to follow up quickly on some of Craig's -- his line of thought. With regard to Empress -- I think Pat had made the notion, or made the comment, that propane prices recover and you start to see a recovery in that business, it's sort of been the same throughout the year. But do you a have a sense of, sort of, what the aggregate price level of that turnaround is? I mean, we see quotes for the U.S. market hub, but what sort of propane price recovery level do you think you need to get to before you start seeing a turnaround on the orange-powered Empress?

Well, we thought about -- Chris, for the whole business, if you just do the arithmetic to hit our projection, I think that all of our NGL barrel would have to average about $1.60 in the second 6 months of the year. We're outlooking more like $0.80 for the full year, so we're not -- based on the forward curve, we're not anticipating a recovery to the kind of level that will get us back to our $1.90 guidance. We're down, probably $0.19 year-to-date, as a result of the commodity effect. And that doesn't fall evenly, exactly throughout the year, but that's probably indicative of prices stayed about where they are, of what the impact would be or what we have to overcome not only at Empress but at our DCP operation to be back to where we were. And we're certainly not forecasting that at this point.

Perfectly clear on that point. No, I wasn't projecting $1.60 NGL for the back half of the year. Now what I was saying is, specifically for Empress, you had made the point that a propane price recovery would lead -- I think it was the first operating loss at Empress that I can remember, and so as long as you guys have given us the quarterly updates there, that business has seemed to produce some operating income, not an operating loss. Granted, you did have some write-downs on the inventory, but what sort of aggregate -- I guess, just a sense -- at what aggregate price level do you need on profane up there in order to get that facility back into profit mode?

Well I think you got to get back to -- you're seeing, kind of, $0.70 type prices now. I think you have to get back up into the $0.80-plus range. The reason why its a little bit difficult to just give that price is because, remember the extraction premium is the other piece, right? If extraction premiums is going to be $2, then you obviously don't need the type of uptick you get on the propane side. But I think you got to start moving back up over $0.80 to get back into the profitability range.

Okay. And I guess, remaining up in Western Canada, you've given some great color in the past on what the LNG export script pipeline looks like. You had mentioned in your prepared remarks and you're advanced discussions on providing some of the pipeline interconnects up there, it seems like every operator with an import terminal here has been talking about converting to export, obviously we saw the NEB give a couple of approvals up in British Columbia. Can you just give a bit more color as to what the nature of the discussions are like today? And maybe what the sticking points are, or hurdles on a go-forward?

Sure. Obviously we're in a competitive environment so I'll keep them relative out. But obviously, when people talk about British Columbia, they often talked about Kitimat. I mean our view is, yes, Kitimat is a great location but it's not the only location. And I think you've seen the government up there talking about multiple locations and the most typical one that's talked about is Prince Rupert. So the 1 pipeline that has been announced, and again, this are all early announcements. Nobody has made FID or anything, it's been to Kitimat. But we think Prince Rupert is a great location, as well, so that might give you a little bit of ideas. I think as you look at some consolidation and folks buying assets in Canada on the upstream side, I think that's probably another indication of the kind of folks that are involved. You've seen CNOOC, Petronas, et cetera involved. Those are the types of players -- and I think you're going to see some aggregation. My view is, you probably don't see 4 or 5 built up there, you see somewhere between 1 and 3 builds. So -- and who knows, on a longer-term perspective, these are all massive pipeline projects for -- not just the LNG side. I mean, they all could be north of -- depending on the size of the plant, north of $4 billion or $5 billion. So you might see some partnerships, et cetera. So that's a little color for you and maybe I'll just leave it there for now.

Okay. And I guess, following real quickly, just on the back of something else Craig had touched on. The New Jersey - New York project, obviously, we've seen some cost pressure there. Now that you're sort of targeting that upper-end of the revised range of $1.2 billion -- given that things are under construction, we're a little bit more than a year away from planned in-service date. What -- I guess, what additional pressures might cause that cost to inflate further? Or are we pretty comfortable with the $1.2 billion at this point?

Well, I'm pretty comfortable with that at this point. I mean, the issues that you face now, or as you're doing directional drills and you have weather, so those are the 2 things that are really technically challenged. We've done well in getting our lands, obviously, our approvals. Equipment isn't a big issue, it's relatively small amount of pipe and compressor work, so I feel very good about those. The issue we always have to watch for is, what happens on directional drills, of which we're doing several of them. And you share in some of that risk with contractors and so you have to -- if you run into something strange with the directional drill. Or as I said, if it suddenly became rainy for 40 days and 40 nights, you can't build pipeline in that type of environment. So those are the risks that -- I'm not sure, there's not really much we can do about those. We've faced those on our pipelines but we're not -- right now, we're on target in terms of our construction activities, our land acquisitions and the like.

Your next question comes from Ross Payne.

Just a quick question on DCP Midstream, LLC given their reduced profitability. How do you anticipate dividend in cashback up to Spectra in the next several quarters?

It's a function, obviously, of their net income where they dividend out most of that -- the bulk of that. So it will all be a function of future commodity prices. And so that's something that is a little bit hard to handicap. You can use the rules of thumb that we've furnished for the effect on DCP of changes in commodity prices and be pretty close in terms of how their distributions go up and down to us.

Yes, typically thinking about 80%, 90% of net income is the way to think about it, Ross.

Your next question is from Nathan Judge.

Just wanted to ask in the spread comment that you made about NGL prices, do you expect Conway to actually fully make up to Belvieu over the 12 to 18 months or will there still remains a basis?

Well, I would think you still -- you can have the transportation basis but I would think overtime, yes, it should close that up. Again, whether that happens as people believe and see the construction completed or whether it takes another 6, 8, 12 months after construction is there -- you got 3 things, you got obviously the supply dynamics and we've seen the supply growth in NGLs consistent with what people thought and obviously we're seeing more supply or less supply than what people thought. Then you got to have the infrastructure build, that's next on the list. And so that gives you 12, 18 months most of that infrastructures built. And then the next big piece is really the demand side of things, of which, you're seeing conversions going on, those that have Nordic current and then the new fracker facilities -- petrochemical facilities that will be built in that mid-decade. So it closes as each one of those start to come to bear, Nathan. But I would expect decks the transportation side of things, that's where you'll end up. I don't think you have good examples on the gas site.

Just as a follow-up on that. And as a, there's a lot of pushback on ethane right now [indiscernible]. Is there an update on what you view how that's going to come out? And the influence on NGL, especially at the Conway basin?

Well, yes. I mean, you're seeing a lot from an ethane rejection perspective. I think you got 2 things, when you're still building off, feeding off some of the inventory build that we had going on late last year. But you've seen ethane prices jump by about 20% even since that low in about 6 weeks ago -- I think they're in the $0.35, $0.36 range today, if the numbers are right. And so yes, I think you're going to see -- ethane is still going to be the positive feedstock out there. I think propane is going to continue to be a more valuable export commodity and you'll start to see that happen. I mean you got 2 big infrastructure plays happening at the end of this year and early next year with respect to -- at the week, we'll triple the monthly capacity to export propane. So I think that will pull up the ethane prices as well.

Actually that's a good segue to what -- my next question. Do you have any interest in getting involved in the propane exports facility business?

Well, sure, I mean we're in the complete NGL infrastructure world. There's a couple of other players that have a pretty good jump on us. But it seems to be a fee-based business which would be attractive if we saw the opportunity to enter that, I think we'd like to do that. I think from a long-term perspective, given where our gas supplies, enhanced NGLs are in North America and where crude is Brent relative to North American gas prices. Exports of propane, they're going to continue to be a very positive future opportunity. So yes, we would definitely look at it.

Your next question is from Faisel Khan.

It's Faisel from Citigroup. I was wondering if you could -- I think you've talked about a little bit on your prepared remarks on some of the questions. But the specific, sort of, cost pressures on the New Jersey - New York expansion, is it with labor unit productivity, right of ways, steel, what were the specifics -- what things driving it up?

Nothing's changed -- just so we're clear, nothing's changed from our outlook at the end of December, early January when we came with the new numbers. A couple of things. One, San Bruno impact, the Michigan oil spill impact, the new pipeline regulations. All of which required thicker pipeline, more directional drills than we had expected. And all of those, therefore, because you got a higher risk as deemed by people on pipeline side. You got contractors that puts some risk into their pricing as well. So it's really those pieces and obviously, we lost 6, 8, 9 months on the regulatory front of when we thought we'd have the thing approved. So it's really past events, nothing that we see from a future perspective.

Okay. So the cost to project is still the same as it was 6 months ago?

Absolutely, correct.

Okay, understood. I just wanted to make that clear. And then just -- I think a little more detail in the Sand Hills and Southern Hills, sort of, construction progress. You said 2/3 done but where are you? Are you seeing any sort of issues with cost? How is that progressing and when, specifically, will those projects be online? I'm trying to think about the months that you think it will be online?

Yes, for sure. So with respect to Southern Hills. In terms of Southern Hills we're 65% done, the first phase. And that will -- that piece is going to come into service -- I'm just making sure I give you the right numbers -- through 2Q of '13 but we've got 65% done. The Sand Hills is going to be -- you get Sand Hills at 65% complete on the first phase. [indiscernible]

That's 65%, that's not both phases. That's the first phase that's coming from Eagle Ford to Mont Belvieu. And the second phase, we're really just getting going in terms of right-of-way acquisitions and for targeting in-service, that is the second phase of 2013.

And in Southern Hills, it's going to end up being -- Southern Hills ends up kicking in...

Mid-2013.

Mid-2013.

But if 65% done it sounds like it could be done a little earlier now or is it still just progressing on time and on budget?

We haven't changed the timeframe but your thought pattern is correct.

[Operator Instructions] Your next question comes from Dennis Coleman.

Just another quick question on Field Services operations, if you would. The change in depreciation, your partner disclosed some numbers yesterday. I'm just sort of wondering, what would've the earnings been? Can you give me an apples-to-apples earnings, if you hadn't made that change? Do you have that number?

Yes, sure. It's going to be about $25 million...

That's our run rate. There was an item that involved some catch up on a look-back basis, so it's about $33 million for us in the second quarter and $25 million ongoing.

$25 million ongoing, so more of a run rate of just under $100 million for the whole Field Services?

Through the year. Yes, that's right.

Your next question is a follow-up question from Nathan Judge.

A quick question on the tax rate, it's quite low this quarter. Are we still on track to meet that 20% -- 29.5% for the full year? Or where do we stand on that?

No, Nathan, we were -- at '11 we were about 29.6%. But you can knock about 2.6% off that for lower earnings in the year, that obviously drives the rate down. And then about another 2% off that for the lower effective tax rate in Canada. We're outlooking about 27% for the year down from 29%. The Canadian tax rate has gone down to about 15% down 1.5 percentage points. So to the extent that we're getting more of our earnings this year from Canada because of the depressed level of earnings at DCP, that helps the mix. That's why its slower.

Then, Nathan, if -- obviously, if you see an uptick in the commodity prices, hence, the earnings from DCP, then your tax rate is going to go back up. Right? Because it's solely a function of the proportionality of Canadian and U.S. earnings.

Sure. So I'm taking it if -- unless there's a recovery in NGL prices, where it really looks at kind of just 27%, maybe 28% for the next several years.

Correct.

That's right.

[Operator Instructions]

Okay, Krista, if there are no more questions, I just like to thank everyone for joining us on the call today. And I would like to remind you that next Tuesday, August 7, we're going to be in New York for a breakfast. So if you haven't already done so, please let us know if you will be able to attend. We look forward to seeing you then. And as always, if you have additional questions, please feel free to call Roni Cappadonna, or me, and we'll help you out. So with that, we'll end the call. Thank you very much for joining in.

This concludes today's Spectra Energy quarterly earnings. You may now disconnect.