Good morning, everyone. My name is Sarah and I will be your conference operator today. At this time, I'd like to welcome you all to the Pembina Pipeline Corporation 2012 Third Quarter Results Conference Call. [Operator Instructions] Thank you. I'd now like to turn the call over to our host, Mr. Bob Michaleski, Pembina Chief Executive Officer. Sir, you may begin your conference.

Thank you, Sarah. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our third quarter 2012 results. I am Bob Michaleski, Pembina's Chief Executive Officer; and joining me today are Peter Robertson, Pembina's Vice President of Finance, Chief Financial Officer; and Scott Burrows, our Senior Manager of Corporate Development Planning. As usual, I'll review the quarterly results we released yesterday, spend a few minutes providing an update on recent developments and then open up the line for questions. I'll start with a reminder that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, projections, risks and assumptions. I will also point out that some of the information I provide refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see Pembina's various financial reports available at pembina.com and on both SEDAR and EDGAR. Actual results could differ materially from the forward-looking statements we may express or imply today. And I'll start off by reviewing our Q3 2012 results, followed by a look at our growth projects, and then we can get to your questions. As you know, this is our second quarter of reporting on a combined entity since closing our acquisition of Provident on April 2. I'm happy to say that during the third quarter, we maintained steady performance across all areas of our business and made strides on growth projects while completing the majority of the integration work we needed to do. We have a few things to wrap up with respect to the information systems integration, but we expect to have this completed by the end of the year. Looking at revenue, operating charge and gross profit EBITDA and earnings during the quarter, you can see that each…

[Operator Instructions] Your first question comes from Linda Ezergailis of TD Securities.

With respect to your Phase 2 expansions that you announced last night, I realize there's a strong fundamental backstopping that. But what sort of level of contracts and what other attributes in terms of term, et cetera, would you require in order to proceed? And when do you expect to get those contracts?

Well, it actually depends a little bit on each of the expansions, but I want to head the Phase 1 expansion for the NGL business. We looked at 10-year terms and our target were approximately 75% of the expansion volumes to give us comfort to proceed. We did, in fact, get something that was probably closer to 90% on that contract for Phase I. So for Phase II, we're targeting about 75%, and again, 10-year term, take-or-pay contracts. On the HPP System [ph], we're looking at shorter term contracts, 25 years will be sufficient for us. And so, again, targeting about 75% of the expanded volumes.

Great. And how might we think of notional financing for that in terms of capital structure, will it come off your balance sheet? And what sort of returns might we expect?

As we've indicated in the past, Linda, our go-forward projects will generally be financed on a 50-50 debt equity basis. And as you know, we've got a large undrawn credit facility available to us, but -- and we have a strong DRIP participation level.

In terms of project returns, I think these are not going to necessarily be dissimilar to what we've experienced in the past. I don't think that we actually have disclosed returns, but I think you can kind of calculate them from based on past experience.

Okay. And just as a follow-up on other parts of your business, are you seeing any inflationary pressures on your projects? And can you give us a sense of what percentage of cost you've now locked down for Saturn and Resthaven?

Yes, Saturn and Resthaven, the gas processing facilities, Linda, we're still expecting the project to come in on-time and on budget. So as far as the gas processing is concerned, I think we're okay. We're not seeing a lot of inflationary pressure there yet. Lead times are, of course, that is something that we have to keep -- be mindful of. As far as the gathering systems are concerned, I think we are starting to see some inflationary pressure there. There's, I think, higher demand for contractors, and that's translating to higher costs. Fortunately for us, that the gathering lines themselves are not that significant in terms of cost. But I think it's fair to say that we are starting to see some inflationary pressure on the pipeline part of the initiatives, but gas plants, so far, coming in on-time and on budget. And Scott, what portion of our cost have we secured on the gas plants?

And so on the Saturn facility, we've ordered 95% of the major equipment and 25% of the site construction is completed. So we only really have about 75% of site construction left, which will be subject to labor inflation. And then on the Resthaven plant, we have about 80% of the major equipment ordered and about 10% of the on-site construction completed.

Yes. So I think with respect to the gas processing assets, I think we're feeling pretty good about our costs to date.

Your next question comes from Robert Kwan of RBC.

On the Northern NGL Phase II expansion, and I guess this ties a little bit into the potential Redwater fractionation expansion, are you trying to tie kind of those 2 processes together? And if there's anything even more specifically, are you offering preferential pricing for customers that would underpin the frac?

You know what, I don't think we can really get into the details of our contracting strategy, Robert. But what I can say is that, it's pretty apparent to us that our customers are going to understand that our pipelines are full and we have to have room for additional processing capability in Alberta. So given that, I think that if you're a customer that's looking for a home for your liquids, you're probably going to be starting to talk about where those liquids might go -- might fractionate them. So I think they're linked, but they're not directly linked at this stage, Robert.

Okay. And I guess with that Phase I and the underpinnings that you got there, and then, obviously, based on your discussions, you feel pretty confident about being able to contract out that Phase II, why haven't we may be seeing enough support for the Redwater fractionator expansion? Do you feel that just -- I think it's the 70,000 barrel a day number that you've been talking about. Is the feedback that maybe that's a little too large and they're worried about getting some protection on spot rates? Or is there some other dynamic going on?

I think it's just -- to complete the story, Robert, I don't think that our customers really have a full appreciation for how much liquids potentially might be coming our way. And I think with the announcement of the HPP Phase II expansion, it's going to become pretty apparent. And we're seeing that actually, once we complete that expansion, based on producer forecast, Robert, we're going to be close to being full again. And so that would suggest that there's a demand, at least, for one additional frac, and who knows? If developments take place, there could be a demand for a further fractionator at Redwater. But I think it's a matter of getting a complete story out there, Robert, to get people to stand behind it. We know we've got a lot of interest in a fractionator at Redwater.

Okay. And just the last question related to that expansion. You’re drilling caverns like crazy on the Redwater site. Do you feel that you have enough caverns based on the pace of development to get ahead or to move forward with this 70,000 barrel a day expansion or...

Yes. I think, Robert, we would probably require one more cavern, and yes. So I think we're in good shape there.

Your next question comes from David Noseworthy of CIBC.

Just a quick follow-on and you kind of touched on the Phase II expansion in the sense that you expect it to be fully utilized by the time it came online. Can we assume the same with -- when you've completed Phase 1 expansions?

Yes.

Okay. Fair enough. And then in terms of the fractionator, in light of recent announcements of other fractionators, is there a possibility that what's needed incrementally, at least in your term, is more C3+ as opposed to C2+?

Well, you know what, I still think there's going to be demand for additional C2+. And I think our customers are trying to establish commercial arrangement where they can get a deal for the ethane. So that's part of the package, David, is that, I think, C2+ fractionator similar to what we have is still in demand to satisfy the chemical folks in Alberta.

Right, okay. And just to have a change of pace here, you mentioned that you're exploring offshore propane export opportunities. In terms of the counterparties that are showing interest, is it more from the producer perspective or is it from like an Asian buyer's perspective? Like what are you seeing there?

I'd say the buyer.

Okay.

Rather than the producer. I think that some -- [indiscernible] to say that, yes. I guess the producers, obviously, will benefit from having an alternative market. And so in a sense, we're hoping we can do the industry some good here.

Absolutely. And then in terms of the need for the buyer, is there a timeline that you're seeing that they're working towards?

We don't have a specific timeframe at this point, David. I mean there's more work being done here in the next month or so. And we may have more to say maybe by the end of the year.

Fair enough. Okay. And then maybe for us just one last question. Can you discuss what liquids-rich gas processing opportunities you're seeing beyond Musreau, Saturn and Resthaven? And perhaps, if you could frame it in the context of what you've seen recently with Paramount's recent decision to back out [indiscernible] for Saskatchewan and Canada selling its pre [indiscernible]mid-stream assets to Enbridge?

Well, I think that if you look at where our pipelines are situated and you look at the geology under our pipelines, what you're going to see, David, is that it's all very consistent geology. I think they're -- people are still talking about a need for more liquids extraction. So I can't talk about specific projects, but we have probably 2 or 3 on the books currently that we are addressing. And we hope to have more to say about that next year.

Okay. And then one last question. You did mention the Phase II expansion, which seems to go up into Northeast British Columbia and Northwest Alberta. What are your thoughts about expanding further south into the southern regions of the Duvernay?

Well, I'd say it's really early innings here, David. I don't think that there's been a lot of Duvernay development as yet. What we are hearing for developments that are taking place, albeit they are very, very, early, that there is a lot of -- potentially, a lot of condensate that might come out of the Duvernay, but more so in the area around Fox Creek. So I think we have to wait for the industry to get further along in their own drilling plans to be able to assess what needs to be done next.

Your next question comes from Juan Plessis of Cannacord Genuity.

It looks like you added some financial contracts in the quarter to hedge a portion of the NGL volumes. Have you fine-tuned your strategy with respect to hedging this business?

Yes. Well we have looked at it in more depth and now and certainly as Bob mentioned on the call, our intent is to lock in cash flow equivalent term minimum at 50% of the gas supply cost. And then we will do that as we -- as a creator's contract for the gas supply itself. And then we'll supplement that with additional derivatives from time to time to effectively lock in up to 50% of our cash flow from the gas supply side of the business. And so, as you indicated, we have commenced that process now and we'll continue that for the balance of this year to certainly lock in a portion of the cash flow for 2013.

Okay, great. And it's mentioned in the MD&A that propane industry inventories have impacted the propane margins. Can you tell us what your shorter term outlook is for propane margins, say, over the next couple of quarters?

Well, what we're looking at right now for propane prices, I'd say on the average, are roughly around $1 a gallon at Mont Belvieu. And we'd created a discount to Mont Belvieu and Edmonton, so I don't see any real significant change here, Juan, at this stage. Typically, when you look at some of the folks that do projections are looking for a stronger fourth quarter, first quarter of next year. But we're staying right in around that $1 per gallon at this stage until we see some movement. It's probably going to take something like colder weather or something of that nature to be -- see a movement in price because there continues to be an oversupply of propane in the market.

Your next question comes from Carl Kirst of BMO Capital Markets.

I think just 2 clean-up questions from my end, and I apologize if you mentioned this in the prepared commentaries, I was scribbling in my notes. But what's been the recent experience with the Empress extraction premiums? We were hearing different things from different players, and just as we sort of enter into the new contract year, I wasn't sure what you guys were seeing.

You know what, Carl, I don't know that we've seen a lot of change in the extraction premiums at Empress. We've heard that at times, people were trying to basically get rid of their product at depressed prices. But I still think that the premiums are going to be fairly consistent to where they have been historically. And although -- gas prices seem to be firming up a bit, so perhaps, you might see some reduction in premium. But at this stage, we're staying the course.

Okay. So basically, 2013 sort of more like 2012, which does kind of put us at risk with propane prices, but basically, no change on that front?

Yes, I think that's fair.

Yes. And just Q3 was basically within pennies of where we were at in Q2.

Okay, thanks, Scott. And then maybe just a broader question, Bob. I'm not sure how much commentary you can put around this, but I know one of the larger projects in the $4 billion backlog was potentially a new Bitumen and diluent pipe to the Oil Sands, west of the river, and we recently saw another competitor go into that area. You've been working closely with someone though for some time. Has that dynamic shifted at all for -- with any color you can perhaps share with us?

No, Carl. I think that -- we continue to work with a couple of parties in an area, and we have got some engineering support with respect to carrying on with the work that we're doing. So I think what it is, Carl, is that these projects, of course, they are large. They require significant capital investment and certain processes have to go through the organization before they can be advanced to a point where they're approved. So I think we're quite aways along the path. But we're not home yet, so we're continuing to work on it.

Your next question comes from Robert Catellier from Macquarie.

Catellier from Macquarie. Just a couple of questions. One of them had been asked, but again, along the fractionator side, I'm curious, it does seem like there's evident demand for fractionation capacity both now and in the future as production grows. I think Kieran [ph] and some other participants see it the same way. So I'm wondering what your appetite is to build a C3+ fractionator that might not have the usual level of contractual commitment. In other words, do you have any appetite to maybe take that on a little bit more on a spec basis than a contracted basis?

I don't know, Rob. I don't think we're going to change the approach that we would take. And I think to give you a little bit of flavor to this, there is a huge demand for additional fractionation capacity right now. And so we've got a lot of people that are looking for service, and I think they appreciate that if we're going to build a facility and it's going to cost close to $400 million, then they're going to have to contract up for that capacity. So no, I don't think we'll be looking at building anything really on spec here, Rob.

Another potential alternative for the propane market, you're obviously considering offshore, but railing, you really have a very good position in Sarnia, but railing to the U.S. is another alternative. Is that a strategy you're exploring in greater detail, perhaps getting some terminal assets down in the U.S. and positioning yourselves that way?

It hasn't been at the top of the list of priorities at this stage, Rob. I think we're more and more focused on what we do in Western Canada, particularly in light of the fact that if we expect to have another fractionator at Redwater, that's going to give us a lot more propane and butane to deal with. And so I think our focus really has been where there's most interest at this stage, which appears to be a terminal on the West Coast.

Your next question comes from Matthew Akman of Scotia Bank.

On the integration of Provident, I'm just wondering if you could provide an update in terms of the organizational side of it. I noticed that the G&A still remains pretty high. Sounds like so far, you've pretty much kept everyone. How's the integration going? Are there any potential cost synergies that you might see over the next 12 to 18 months there?

Well, just a comment on the integration, I think it's gone quite well. You are right, we have hired the majority of the people from Provident that, well, we wanted to hire. We are running a bit of a dual track here in the sense that we have different, if you like, information systems that we're using, and so hopefully see that we're going to see a consolidation of those systems by the beginning of next year. So that's on the positive side. Also and looking at it as well, Matthew, when we put together, if you like, the Pembina budget with the Provident budget that was adjusted to reflect the removal of some of the corporate-related costs and senior executive staff, that we did achieve a $10 million reduction compared to the 2 companies on a standalone basis. So there were some cost savings, and those were pretty much identified at the time of the acquisition. So I think it's proceeding according to plan. One thing here you've got to appreciate is that we got -- so we got a much larger organization now with significant growth continuing. So we still have to have the people internally to be able to handle the growth and growth in areas that perhaps, we hadn't considered in the past, whether it's an export terminal or whether it's building a new fractionator or expanding our pipeline systems, there's a lot of stuff going on here right now. So -- but I'd say, my comment on the integration itself is it has gone as well as we could expect. And so we're going to go here by the end of the year as far as all systems are concerned, and we've got the people as physically integrated as we can, our only issue here is we may not have enough space for everybody.

Right. Another question on the cost side relating to the pipeline business, the conventional business. And I noticed costs were down year-over-year, and you attributed that partly to power expense. But in a world where there's increased scrutiny by regulators on integrity management, I'm just wondering if you feel like you're in good shape that way or whether do you see possible cost escalation unconventional, especially if you expand the kind of stress the existing pipes to full for maintenance capital?

Yes. You know what, Matthew, we've got a significant integrity-related program underway currently. We're spending a lot of money in the fourth quarter of this year. In fact, I think this year, we'll be spending probably, in total, about $50 million, 5-0, on integrity-related expenditures. And that would compare to, say, about $30 million in the past. And I think for 2013, we're probably going to be somewhere in that $40 million to $50 million range again. So we are funding a lot of the work to ensure that when we see the increased volumes on our pipelines, that we're satisfied that the integrity of the pipeline is there to handle the increased pressures.

Yes. And Peter, is that being expensed or capitalized?

Well, where we can associate integrity work with increased volumes or increased operating pressure, then those amounts would be capitalized. But other than that, our routine integrity inspection dig work would all be expensed.

Your last question comes from Steven Paget of FirstEnergy.

It's just a follow-up to your previous one. And just how much of Saturn, Resthaven's costs are going to be on major equipment? How much is for the lego set, I guess, and how much is for putting it together, the site construction?

That's a good question, Steven. I don't know that I've actually got the details. Scott, do you have anything, roughly?

Roughly, 50-50.

Roughly, 50-50, okay. So -- and once something's ordered, the price is locked in?

Yes.

There are no further questions queued up at this time. I'd turn the call back over to presenters.

All right. Well, thanks, Sarah. Thanks for everybody who participated on the call this morning. I guess to the extent that we've tried to answer your questions that we haven't, I'll let you know you can call Scott, because he's got all the answers that I don't have. So thanks very much.

This does conclude today's conference call. You may now disconnect.