Good morning everyone. My name is Sarah and I will be your conference operator today. At this time I would like to welcome you all to the Pembina Pipeline Corporation 2012 second quarter results conference call. (Operator Instructions) Thank you. I would now like to turn the call over to our host, Mr. Bob Michaleski, Chief Executive Officer. You may begin your conference.

Thank you Sarah and good morning everyone. And welcome to Pembina’s conference call and webcast to review our second quarter 2012 results. I'm Bob Michaleski, Pembina’s Chief Executive Officer. Joining me on the call today are Peter Robertson, Pembina’s Vice President of Finance, Chief Financial Officer, Glenys Hermanutz, our Vice President of Corporate Affairs, Bob Lock our Vice President of our NGL business and Scott Burrows, our Senior Manager of Corporate Development and Planning. As usual I'll review the quarterly results we released yesterday and spend a few minutes providing an update on recent developments including our acquisition of Provident Energy and then we will open the line for questions. I'll start with a reminder that some of the comments made today maybe forward-looking in nature and are based on Pembina’s current expectations, estimates, projections, risks and assumptions and I must 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. The second quarter and the first half of the year has been a very busy time. We closed our acquisition of Provident on April 2 and since then we have made a lot of progress on our integration activities. As you know, we are listed on New York Stock exchange and that made substantial progress on bringing our two teams together. This is the first quarter we are reporting as a combined entity which also means that this is the first time, we’re presenting results that show a consolidated view of our business and includes those assets that are new to Pembina. Admittedly we are…

(Operator Instructions) The first question comes from Linda Ezergailis of TD Securities. Your line is now open.

Thank you. I just wanted talk a little bit more about your dividend. Clearly, you are confident in the dividend level, but I am just wondering what sort of growth we might expect over the next couple of years given the commodity price headwinds you are facing might the board consider kind of pausing growth until your proportion of fee for service cash flow increase and when you look at a payout ratio would 70% to 80% payout of total free cash flow still be what the board might be targeting or might the board more focused on non-commodity based or product margin based cash c

Linda I am sorry I will just try to answer the several questions I think that were there embedded in that, first of all I don’t believe that we just had a board meeting yesterday and I don’t think there is any indication for the board that we are going to change our growth targets or plans for the future. Obviously, in the near term we have been impacted by the commodity price environment that impacts had an impact on the second quarter results for the NGL business unit, but longer term we have taken a look at the numbers and we don’t see any material change in our ability to generate growth going forward, we had targeted growth in a range of 8% to 10% per share in a softer commodity price environment, I think that might be off a bit but not lot. So I think that we are going to stay to course with respect to the growth initiatives that we do have in front of us, I would have to say that the unrisked capital we have in front of us Linda that almost all of that I would say and I think in fact instead to stay that its say that almost all of it is related to fee for service business. So we will see that commodity related exposure come down overtime and but it will take us to spend CAD3 billion to CAD4 billion a year it’s going to take four year to five years too, so we would expect overtime that commodity related close part of our business will come down and the other part we will have to look at as well is really the commercial terms that we have in the commodity expose business as to whether there is an opportunity for us to look at that business model little bit differently going forward but it’s already (inaudible) so I think we are going to stay the course and do what we have been doing and we will adapt to the environment that we are in.

And the dividend policy will that be adapted perhaps in the short term or did your dividend policy look at kind of the long-term to growth trajectory and not change in the short-term in terms of the growth rate?

Yeah, I think we are still on the same course that we (inaudible) before our longer term plans for dividend growth within in that 3% to 5% per year I think it will be depended to a certain extent on what happens in the commodity price environment but I think that still remains and payout ratio is 70% to 80% you talked about I think it’s reasonable.

Great, thank you. And just a quick follow-up question I don’t know if I should be taking this online. I really appreciate your addition of butane strip pricing and your hedging disclosure, would it be possible potentially to provide similar condensate pricing on a historical and strip basin or continue to provide an NGL basket as a percentage of WTI?

We will take that under consideration Linda.

Your next question comes from Robert Kwan of RBC Capital Markets.

Bob you touched on the strong liquidity that you got right now, I am just wondering that as you do look out at the funding plan and the cash flow lease deck at current commodity prices probably has come down versus budget, what are your thoughts on external funding slightly around the need for some common equity and within that are there any, would that cause any potential for some capital rationing to focus in on highest return projects?

Well, Robert I think its fair to say that we do look at all of our projects on the basis that those are, there always will be combination, we are going to have some in the near term that are perhaps, will generate what we consider to be modest returns but over time will generate more positive returns, and so we have all those projects underway and they will vary from the gas services business unit to the conventional pipeline business unit to our mid stream and NGL business units and oil sands need to both have, those businesses have different profiles, different risk profiles and different return profiles but I personally like a well balanced approach to it Robert and in terms of financing you know clearly we look at it longer term, we finance our initiatives roughly 50-50 debt and equity so we've got plans to spend somewhere between CAD700 million and CAD800 million this year of the [drip] raise just something in excess of CAD200 million. So I think that probably by the end of this year early next year we are going to have to be looking at some form of equity issue and then that will be entirely consistent with where we were, you know, a quarter ago. So I don’t think our plans are maturely changes as a result of some of the change in influences commodity prices.

Maybe just a last question with the potential reversal and repurposing of the coach and pipeline works quite well in terms of where they want to run that from compensate going into Redwater as well some ability to move the propane out. Can you just talk about how are you thinking about that balancing Redwater against Nexus terminal and some of the opportunities for you and what you might be doing right now to try to get out in front of that?

Well, there is a number of developments, some of which I can’t talk about Robert. So I'll just say that the reversal of the coach pipeline will result in condensate getting up to Redwater we see that’s going to lead reach another source of condensate per Oil Sands applies so that it fits with our overall strategy, the [PENT] we’re also developing the PNT with us other like connections and other connections that we are also going to use as a hub to launch condensate for till he went five for Oil Sands activity with respect to your question on moving other liquids out. You know, I think it's fair to say that we are not going to sit idle by I think that there has been a lot of changes taking place in the liquids market. We need to find other outlets for liquids out of the Saskatchewan area, including looking at liquids moving to the West Coast possibly and that’s something that we will also look out and consider in terms of go forward position. So we are looking at a number of things and we will have a number of options to consider here but I think the conditions are changing; they are changing in response increased demand for diluent open oil sands, but also we have to find a way to get product out of Alberta to different markets as well.

Next question comes from Juan Plessis of Canaccord Genuity. Your line is now open.

As you mentioned in your remarks Bob, you now have four plus months operating the problem assets; going forward do you see yourselves making changes to the NGL hedging strategy and if so what changes do you envision?

You know one, that is under review currently, we have not entered into any new hedges in the last 12 months and we have unbound the one I referred to with respect to the oil hedge. I think it’s fair to say we really want to get understand the business and the business profile going forward before we really commit to a longer-term strategy; it’s not to say that we are not going to look at hedging strategy, but right now I think it’s fair to say that we want to understand the implications that are going forward and I alluded a little bit to the fact that we need to understand the commercial model as well as to whether that commercial model with the exposure to commodity prices makes sense for us long-term. I think over time we are saying that we are going to spend money on fee for service business and the commodity exposed portion might decrease and if we have a hedged position there that would be totally acceptable. But what we have done so far is really just fall of through with the program that was in place and improved by the provident board and we just want to get smarter about it.

And with respect to the red water fractionator at what level of contracting would you be comfortable with to move forward with the project and can you talk a little bit about the potential capital costs of that project?

Well, with respect to the level of contracting, we reviewed that yesterday and I think we are seeing quite a bit of it, just probably in excess of 100% of the capacity. But I think in terms of commercial commitments I think we will be pretty comfortable moving at ahead at 50 to 60% of contracted capacity on that fractionator; I think there is a number of people that are sort of leading in the -- if you are like wait to see what happens there. In terms of capital costs I think we have given broad guidance in the past, but I would say that we are looking at something between CAD350 million and CAD400 million for 70,000 barrel a day fractionator.

Your next question comes from David Noseworthy of CIBC. Your line is now open.

Just wanted to better understand a bit what happened in the quarter in terms of midstream sector and kind of what we are looking at going forward. Historically, your gas supply has been contracted I believe kind of one-third, one-third basis both monthly and long-term has this changed materially?

I don’t believe it’s changed materially during the quarter, although I think the sport market probably is not something that we have been focusing too much on at this stage. One of the issues we have got David, we don’t have a lot of place to store and the production that we can generate we are very pretty much full up for all of our storage for the quarter, so that does have an impact on what we do commercially as well.

And does that situation both in krone and red water?

Yeah I think that applies to both.

And then so then when you speak of the extraction premiums reflecting a longer term, higher longer term frac spread, is that so that would be more on your long-term gas supply contract, but certainly not on the spot, like have we seen the spot come down, I guess in terms of when you are processing those volumes?

Yeah, I think we've seen the supply come down more recently the problem we have is we can't really take advantage of that lower priced spot market because we don't have any place to put the product. David I don't think that's similar to a lot of people at this stage, I mean we are long NGL and in North America and so until the market clears, either increasing demand and we are seeing that. The more recent increase in the price for propane is I mean that's a positive development and I think our people also think that there's going to be a fairly significant increase in export capacity in the Gulf Coast here in the next 12 months which should help alleviate some of the oversupply as well.

In terms of when we look at your results in trying to compare on a year-over-year basis, on a potential basis how does the providence of old commercial service segment operating margins breakout between Redwater West and Empress East?

Yeah, I don't have that level of detail, maybe Scott you want to answer that question?

Yeah, about 25% to 35% of commercial services is in Empress East.

And then finally, in terms of the Alberta ethane prices, have they recovered at all with the completion of the turnaround and I know that and or what are you seeing there.

Yeah, David I don't know specifically, I do know that as a part of our overall programs to offer services to our customers that we’re working with the people in the petrochemical business for them to offer long-term commercial contracts to our customers at prices that are going to be acceptable to them, for you know, 10 to 15 years. So I can’t speak specifically to the pricing that they are arranging because that's between themselves and the producers but I know that they do want to enter into long-term commitments to back stop capacity additions at their facilities and so that fits very well with our overall strategy of dealing with all the products that come in the NGL business, because we don’t want to control what happens with ethane and ethane pricing, but if the customers can get into long-term contracts that fits very well with the overall service that we are going to offer.

And your producer in that so far has been positive towards wanting to extract CTU plus mix because of these contracts?

I think that’s a fair comment; yes.

And maybe just one last question. There was a mentioned about looking for new markets for some of these NGLs. In terms of, what is your tonnage capacity to produce water borne quality, or export quality, propane at red water?

Currently, I'll turn the question to Bob Lock.

David, thank you. We’re looking at that certainly. So we are producing a product quality that’s not, I guess at this point water borne, but it is typically water quality or water content in the propane that we would be looking to taking out. So as we expanded our own proprietary, the view of what we might be out there for options for us will be looking to putting additional treatment to that.

Do you have any idea at this point what kind of equipment that would take or kind of CapEx that would be required?

It’s certainly days for that, but where we are looking at those options it really comes down to what volume it is we are looking.

Fair enough and would it make sense do that as part of an expansion of the fractionator or is it totally separate?

It may.

Your next question comes from Carl Kirst of BMO Capital. Your line is now open.

Most of my questions have been hit, may be just a couple of cleanups and first actually perhaps starting on the DC market as far as potentially moving liquids west and we kind of generally tend to think all about propane export right now. Is there a possibility of doing other water borne product export or would the market for the West Coast really principally just be a propone one?

I think there will primarily be a propone way; when you look at the liquids that are produced condensate is going to be consumed in Alberta, the butane will like to be consumed in Alberta, the ethane will be like to be consumed in Albert, so it’s really the propone market which would try to find the market like the elsewhere.

And then just another follow-up on Empress East and the extraction premium; is it possible to say what the current mix of extraction premium is right now or what was paid in the second quarter. And I was also trying to get a sense of what that portion that is term supply, what is the tenure of that, is that something that we think the contract year basically being able to April perhaps with the rest of those contracts kind of roll off by April 2013?

I will let Bob address that and I am not sure if there is any commercial issues here that we might be sensitive to Carl, but I will let Bob Lock try to address that question as best as he can.

Carl, I can answer basically half of that I think. On a term basis the Empress contracts on an annualized basis are on the gas year so these deals are done in conjunction with transportation arrangements on the pipeline so those are November 1st deals, so they would have an exploration profile of November 1st to October 31st every year. As it comes down to breaking up how much of our portfolio would have on the month the to month seasonally and with the daily options that there are out there, we don't really disclose that so the pricing specifically to those terms are not currently available.

And I think there's some sensitivity around pricing because that's obviously a competitive market at Empress Carl.

No, understood and whatever out of market extraction premiums you are paying right now hopefully that will be alleviated soon then.

So we have term deals that would expire on October 31st of this year.

Your next question comes from Matthew Akman of Scotia Bank.

I just, you know obviously you guys didn't buy provident primarily for Empress, you know having said that, I am sure you expected to make a positive contribution, you know I guess to what degree were you surprised by the extent of swing that could occur there and what have you I guess learned in the last few months in terms of how to at least get it profitable and to avoid this kind of extreme results?

Yeah, I think Matthew, that’s a really good question and I have to say that, you know, we’re learning as we go here too. I think the circumstances during this second quarter and particularly during the month of June, we are not expected. I don’t think expected by anybody when you look at the decline in the commodity pricing. Some of the product production was hedged but obviously not enough. But I think looking forward, you know, we're looking at Q3 and Q4 as we're turning to fairly solid contributions from Redwater and Empress in response really to, if you like even a fairly conservative estimate of where propane prices might be. So it's been a bad quarter. It's been a bad month, but I look at this deal like as you alluded to. This deal is a long-term deal. It's going to take us probably a year to two to even identify all of the revenue synergies that we can achieve and after we identify them, there is more to come. So clearly our view is longer term. As Scott look out, that going forward the results over the next three to four years on an assumed lower commodity price environment. But you know what, it still doesn’t look that bad. In fact it looks very good and you know, the projections that we have been public with I am still prepared to stand behind those in terms of cash flow per share growth and dividend growth. So it's been a bad quarter.

I guess the other guys that have (inaudible) didn’t do so hard in the quarter either. I mean, Spectra didn’t really make money there. I imagine Plains of looking at this with kind of a new view. I mean there is got to be a feeling among the Empress guys. We’re not going to pay this level of premiums any more. Is that your sense of kind of consensus among the Empress owners?

You know I personally have not talked to. But I know that I do have some conversations that are going to be coming up here with respect to Empress and what needs to be done there. I think that it’s fair to say that there is excess capacity at Empress. I think it’s got this processing capacity of something like 12 Bcf per day with about force going through it. So obviously there is excess capacity and people chasing it quite competitively and perhaps there should be a rationalization that Empress and I think that’s something that needs to be discussed further. But at this stage it’s a conversation and some people they might be may not be as interested in doing something there because it may not represent a lot of their cash flow, but I still think going forward something should be done there.

My final question as you touched on it little bit but I want to have some more directly which is on your hedging policy. I am sure you are going to take some time to review the hedging policy, but we have seen a trend among some of the players there to reduce hedging of frac spread in Alberta. I mean [Spectra] doesn’t hedge at. Interpipe I think it’s going to hedge less because fee based is outweighing commodity based cash flow and I think that’s the same with Pembina as you guys grow, it has not hedging at all these frac spreads an option that might be on the table going forward?

I think all the options are on table including that one that’s why I think like I said we want to spend more time understanding, we have got some legacy hedges that were in place in Provident that we will unwind here in the first quarter of next year and I think it will be fair for us to look at that position and prior to them expiring and so we are looking at that now. We review our hedging position on a monthly basis and I can tell you like for me personally I am not big on hedging, but there could be a scenario here where it does make sense. I would say that longer term to the extent that the commodity exposed part of our business gets less I'd be less inclined to hedge.

Your next question comes from Robert Catellier of Macquarie.

I just want to follow-up a little bit on the Empress conversation. I think as Matthew pointed out the players there aren't making much money. You yourself are one of the more efficient plans and if I take Scott’s comments of 25% to 30% of the commercial revenue of Provident being allocated to Empress, it doesn't look like Pembina made any money on the frac spread business at all. So the implications there have that the extraction premiums have to come down because nobody is making any money. Do you want to comment on that?

Yeah, I think Rob that's a fair comment. I would agree with that that if you are not making any money, why do it. You know that's kind of the business. So we've got to do a fair amount of (inaudible) to see what makes sense long term.

Okay, just getting beyond that for a minute on the propane side. You know there's export capacity that is getting to build up. I am wondering what if (inaudible) or the company has a view on assuming a normal winter, how long does it take the propane market to rebalance given the increasing export capacity?

The sense I got Rob, which is expected that it's going to be like some spur around the first quarter of next year if we assume that we have a normal type winter. Apparently the overhang right now is about 20 million barrels. Enterprise would draw about 3.5 million barrels, so we are saying Q1 2013 we should resort to about a normal situation and there's been a number of other petrochemical type developments also which are increasing demand for propane as well, Rob. So I say while it is early innings, we are seeing realistic Q1 of next year.

And then further of the hedging question a little bit, Obviously there is some fracs and there is marketing, you know, does the Provident strategy that you re running with now until you make evaluation. Does that hedge any of the marketing exposure at all?

Bob, I can’t answer that question. Rob?

We do have some clean propane, butane and condensate hedges in for the balance of 2012 but beyond 2012 we’re still evaluating our go forward plan.

Okay, and then as the, when you evaluate the plan, I know you are obviously not finished but is the preference to just stick with, are you more concern I guess about the frac spread or the marketing in term of what you might consider hedging?

I am saying that we are going to say that pretty hard here right now like I said unfortunately it is not like we didn’t to know it but we do have some legacy positions share that we have to get away with through and we are going to be to those in 2013 and I think that we can take a fresh look and we can look and take a fresh look before that as well but it is going to take some next few months to really sort our way through that but I would be interested you know as we talk about we got some of the personal views and I think we like to explore some of your thoughts on the subject as well because I say this is a bit new to us and something that we want to fully understand before we can make any commitment.

But the other part I notice on the updated hedging guidance there is a mismatch between the percent of the NGLs hedged and the amount of gas hedged. So more hedge on gas it creates a bit of basis risk, so maybe you can just talk about what sort of exposure you have then to those changing dynamics?

Well that’s part of the legacy situation I discusses Rob there was a higher percentage of a gas that was hedged historically and gas volumes have down as also we are probably 80% hedged on volume which isn’t necessarily where wanted to believe to anybody wanted to be so that’s kind of sort of tell in time out in time so there is a proper balance between the gas and the products.

And then just my final question is just housekeeping Provident formerly had maintenance capital reported as Pembina was in fact was exposing everything, so what happens to how do we review the maintenance capital requirements capital requirements that probably going to have previously are those now being expensed?

Probably Peter with answer that question.

These are fairly small amounts for the second quarter. If they were capitalized before they will continue to be capitalized, for the quarter that’s only about just over 2 million for the quarter and I would expect for the year, assuming nothing has changed and how we categorize that maintenance capital I would expect CAD8 million to CAD10 million for the nine months for 2012.

So Peter I will ask you this question so what our intention that we would be capitalized how do we…

Maintenance capital as you know is not a GAAP measure so how we define its subjective so we really have to see if this additional capital is that we get additional revenue out of this additional capital certainly on our legacy assets, we spend capital on our conventional systems and generally that additional capital attracts the toll in the following year, so we view that as development capital the Provident assets may be a little bit different if we can get additional revenue on those front lines of capital.

Just keep on with the modeling we have previously with Provident till you tell us there is a change in the treatment?

Yeah I think that’s fair.

The next question comes from Steven Paget of FirstEnergy. Your line is now open.

Just noticing your oil sands net operating income is off a bit versus the first quarter I am wondering if you could let us know if there are drivers behind some of that?

Yeah I think on the Nipisi, Mitsue puddling, Steven we were slightly off on the commitment of that resulted in lower operating income for the second quarter compared to first quarter. I think the situation has been rectified with it really had to do with the ground temperature conditions impacted the amount of product we can move plus change in diluent sucks so those things have now I think been pretty much behind us and so we expect the third quarter to return to more normal proposition for the Nipisi pipeline.

You mentioned that both (inaudible) would it make sense or maybe you are doing this already to being moving out NGLs in any and always possible whether it’s real or I guess a truck is probably not economic but moving things by rail of the Gulf Coast?

I will let Bob Lock answer that question Steven.

Thanks Steven. Without question our marketing folks are spending in an intense amount of time and effort for trying to place product, but the challenge we've got is placing into a market that's really soft in this quarter. So to the extent possible we are looking at working with folks that have offshore capacity, the cost to get there obviously is a fact and what the net factor we would realize it as a factor, so we are trimming back our supply a little bit and we are trying to manage within our storage constraints. Certainly, August is our bench point for storage, so expect sales in our traditional markets to start picking up here in September.

And how should we be looking at third quarter volumes at Empress East and red water west given the performance of the storage?

So again I think we are tight-spot here for containing supplies in the summer months, because we pass along with every other player in the storage business for propane and started the summer with higher than average inventories, so once we are through that our expected sales profile should we very similar to our historical performance.

Yeah, the only comment that is Bob we have an expansion under we had at red water, is that going to impact our production for September?

So Bob is right we are undergoing a debottleneck project at red water for about 48,000 barrels a day and we expect that to be online for October. So it won't have a tremendous impact on the third quarter, but fourth quarter we will be having more product available.

Thank you. So that so I guess ignore the last part of that conversation Steve.

So third quarter for production volumes looks pretty good then?

Yeah, compared to, it’s comparable to the past.

(Operator Instructions) Your next question comes from David Noseworthy of CIBC.

Just a few questions here on the oil sands, we have some recent announcements by IPL and Trent regarding new oil sands pipeline and can you talk about what you see in terms of need for additional oil sands, (inaudible) transportation capacity over the next two to four years?

Well what we can see, there was an announcement, I think that there is a number of different that require services in the oil sands and so we are still looking at supply and return to areas that are we are familiar and I think we will have more to say in time. But we still that there is going to sufficient demand and I think one of the advantage is that we have now to the Provident acquisition and development of our storage facility is sourcing diluent from a number of different places that we think very attractive to potential customers in the oil sands area.

That kind of leads into my next question; in terms of providing logistics contracts we have seen with the coal project I guess I recover there, tried up a dulient logistics contract. Do you see an opportunity on the expanded Polaris pipeline to provide some more?

I really cant comment on that.

And then just on for the capacity I think it was 60 ounces per day that you expect to see there; will that additional capacity require any kind of capacity expansion at (inaudible)?

No.

At this time I would like to turn the call back over to the presenters for closing remarks.

Okay, well thanks for participating this morning and obviously there is a lot of interest in what’s going on in the NGL business and we are quite interested in that as well. We are learning as we go, but I think that we are still very optimistic about what the Provident transaction will mean to us. We are still very positive on all the projects that we have and these haven’t changed there. So we will have more to say as we progress to the next couple of quarters, but we are pretty optimistic about what the future looks like. So thanks for your participation this morning and if you got any other questions, you can talk to Glenys, or Scott or Peter because I am nearly away for a week.

This concludes today’s conference call and you may now disconnect.