Pembina Pipeline Corp (PBA) 2012 Q2 法說會逐字稿

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 second quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks there will be a question and answer session.

(Operator Instructions)

Thank you. I'd 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. Welcome to Pembina's conference call and webcast to review our second Quarter 2012 results. I am Bob Michaleski, Pembina's Chief Executive Officer. Joining me on the call today are Peter Robertson, Pembina's Vice President of Finance and 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 will review the quarterly results we released yesterday's and spend a few minutes providing an update on recent developments including our acquisition of Provident Energy, 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 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 www.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 first half of the year has been a very busy time. We closed our acquisition of Providence on April 2 and since then we have made a lot of progress on our integration activities. As you know, we listed on the New York Stock Exchange, and have 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 are presenting results that show a consolidated view of our business and includes those assets that are new to Pembina. Admittedly we are faced with a challenging propane market conditions that impact our result of quarter, but we maintained steady performance across all areas of our business while managing the integration work we needed to do.

I'll give a high-level overview of the results in a minute but I'd like to start off by talking a little more specifically about the progress we are making on integration. It's so early in the game for us, we have only owned these assets for just over four months, but so far integration is going very well. We are seeing real upside possibilities associated with these assets. And we have retained a great group of people, people who have the knowledge and experience to help us achieve Pembina's future goals. I am very happy to say that as of mid-July we have moved all of the former Calgary Provident employee's to our head office in Calgary, which will now give us the chance to begin working even more closely as a single team focused on a common set of goals.

Our employees had to deal with a high volume of change during the quarter, yet I am proud that they were able to achieve solid results in each of our businesses despite the attention required for the integration. This integration has tested every aspect of our business. We're not just combining two companies, we are identifying the best processes and practices to adopt moving forward.

Now, let's look at Pembina's Q2 results compared to the same quarter last year. With such a large acquisition reported numbers look quite a bit different than what you're used to so I will try to add some color. I want to start off by saying that we're confident in the strong fundamental story of our business. We didn't undertake this acquisition for three months worth of results, but for the long-term benefits we see evolving from our industry-leading suite of integrated assets. To provide a bit of context before getting in to the specifics, the NGL business we acquired from Provident is a seasonal business during which the second quarter traditionally contributes lower operating margins due to NGL sales and weaker pricing in the summer months. Propane prices were as low as CAD0.73 per gallon in June of 2012 compared to CAD1.26 per gallon in the first quarter of 2012 and CAD1.50 this time last year. Current propane prices our CAD0.94 per gallon and the futures price for the second half of the year average about CAD0.95 per gallon.

Looking at revenue, operating margin, gross profit, EBITDA and earnings, you can see that each of these metrics have increased for the quarter and year-to-date, largely as a result of the acquisition, continued solid performance all of Pembina's legacy businesses. A significant unrealized gain on commodity related, derivative financial instruments also built up our results. Pembina is required to employ a mark-to-market accounting for all unrealized gains and losses associated with financial derivative instruments at a point in time and report this against current period earnings. This can result in quarterly variations that are not necessarily related to current operations. When you look at earnings and per share in capital per share, however, you'll see that these metrics are down on a year-over-year basis. The majority of the variance is related to the issuance of 116.5 million shares to complete the acquisition. And, to the lower than average propane pricing in the second quarter which as I previously mentioned is usually the softest quarter in the NGL business. We also incurred higher depreciation and amortization expenses related to our expanded asset base, higher interest and acquisition related expenses, as well as a significant increase in working capital, which reflects a seasonal inventory build.

Turning now to look in more detail at each business. Throughput on our Conventional pipelines averaged 434,000 barrels per day during the quarter, approximately 5% higher than the same period in 2011. Volume was impacted in the second quarter by an outage at a third-party facility, which caused a portion of NGL volumes to be shut in. On a year-to-date basis, SPUTA is up by 12% compared to the first half of 2011. In the second quarter revenue generated by our Conventional Pipeline's business increased by 8%, while operating margin dropped by 5% due to increased operating expenses related to integrity and geo-technical work. That said, revenue and operating margin are both up for the first six months of the year by 13% and 8% respectively.

Our Oil Sands and Heavy Oil business delivered a 42% increase in revenue and a 39% increase in operating margin in the second quarter of this year. These increases were largely due to the contributions for our Nipisi and Mitsue pipelines, which began operations in the third quarter of 2011. Those pipelines drove up the year-to-date performance, as well, with revenue and operating margin up by 42% and 47% respectively from the first half of last year. Our Gas Services business processed higher volumes at our Cutbank Complex during the quarter, and realized an increase in revenue of 19% and a 12% bump in operating margin when compared to the second quarter of 2011. The same factors drove up the year-to-date results with revenue and operating margin increasing 23% and 19% respectively compared to the same period of 2011.

We've combined the former Provident business results with our Midstream group, so that accounts for the majority of the large increase in this segment during the quarter and first half of the year. During the second quarter, we saw a 240% increase in revenue, net of costs of goods sold at 116% increase in operating margin over the same quarter of last year. For the first six months of 2012, revenue net of cost of goods sold jumped 119%, while operating margin came in 73% higher.

Our Crude Oil Midstream business, which represents Pembina's legacy Midstream and Marketing segment contributed operating margin of CAD30.8 million compared to CAD26.8 million during the second quarter 2011. Year-to-date operating margin was CAD60.2 million up 19% from CAD50.5 million in the same period last year, which was driven by higher pipeline volumes, wider margins and new services at Pembina's Nexus terminal. Redwater West and Empress East both acquired through the acquisition and which represent our NGL Midstream business, generated operating margin of CAD36.2 million and CAD2.2 million respectively, excluding realized losses from commodity related derivative financial instruments. As I mentioned early we our facing some headwinds with respect to weak propane prices and during the quarter results were impacted by a propane inventory write-down of CAD8.4 million.

Industry inventory levels remain high due to the relatively warm winter in North America, and the cost of Pembina's NGL inventory was above market prices resulting in the write-down. Once we emerged from the overhang from the record mild 2011/2012 winter, and assuming typical winter weather this season, combined with increased export capacity in the Gulf Coast, we are optimistic that the propane environment will improve as the year progresses. Also this past quarter, we teamed up our hedging position by buying out the remaining portion of Provident's legacy crude oil hedges for CAD1.1 million, as we believe these were not effective hedges for NGL prices. As a result, Pembina no longer has any propane or butane hedges linked to oil prices. We have updated our hedging information posted on a website under Investor Centre.

Corporately, we incurred G&A expenses of CAD25.8 million during the quarter compared to CAD12.8 million during the second quarter of 2011, due to the addition of employee who joined Pembina from Provident, increase in salaries and benefits for existing and new employees, and increased rent for new and expanded office space. The same analysis applies to year-to-date numbers for G&A for the first six months of the year, totaled CAD43.3 million, up from CAD27.4 million in the first half of 2011. To help put these things into perspective, our administrative staff has almost doubled since this time last year.

Before I move on to discuss our growth projects, I would also like to mention that in conjunction with the closing of the acquisition, we increased our monthly dividends from CAD0.13 per share per month, CAD1.56 analyzed, to CAD0.135 per share per month, or CAD1.62 annualized, which became effective with the April 25 record date. We're confident that the depth and breadth of services we are now able to offer customers is a key differentiator that positions Pembina for significant growth in the years to come and that means we view our dividend as sustainable for the foreseeable future.

Now, let's look at how we're progressing on our growth projects. I'm not going to go into too much detail here as I trust most to be on the call have the information from the second quarter report and we can cover on more specific questions once I've finished my prepared remarks. What I would like to stress, though, is the additional fee-for-service and take-or-pay contracts that Pembina secured in the second quarter. Starting with our Conventional Pipeline business, we are very happy to announce that during the second quarter we reached our contractual threshold to proceed with the 52,000 barrel per day Northern NGL expansion. We expect that the expansion to cost approximately CAD100 million in total and have plans to bring 17,000 barrels per day on stream by the end of 2012, with the remaining 35,000 barrels per day by the end of 2013.

Now that we've reached satisfactory arrangements with our customers and our well on our way with required environment and regulatory approvals, we're hitting the ground running to construct the first phase of the expansion. In fact, we've already been working on two of the three pump stations as part of the Phase One expansion. We've also recently increase the capacity of Drayton Valley main line by 50,000 barrels per day, bringing the total capacity of the system to approximately 190,000 barrels per day by refurbishing our Calmar booster station. This is good news for our customers, as the system was constrained due to high levels of producer activity in the area. On the pipeline portions of the Resthaven and Saturn projects, we're working with our stakeholders and regulatory bodies on environmental planning and route selection and are completing preliminary engineering work. We our nearing submission of our ERCB applications and are finalizing agreements with a number of First Nations communities regarding their interests in the project area and potential business and employment opportunities.

Now turning to Gas Services, we're please to report that over the next few days we'll be commissioning the new 50 million cubic feet a day shallow cut expansion at the Cutbank Complex. For the new Resthaven and Saturn facilities, Pembina is progressing construction at both plant sites. We recently entered into a long-term arrangement for the remaining 50 million cubic feet a day of spare capacity at Saturn, bringing the total contract capacity to 100%. With this arrangement both Saturn and Resthaven are 100% contracted. We are still working on the repairs to the Musreau Deep Cut, which was first placed into service back in February. This facility had been running for about six weeks before a gearbox failure caused us to cease operations. During the outage we're still able to process the gas through our shallow cut facilities at Cutbank and as a result we have not had to shut in any customer's production while we work on the repairs.

In our Midstream business, we are working in a number of growth projects in both our legacy business, the Crude Oil Midstream Group, as well as our new NGL Midstream Group. Over the last couple of quarters we've talked about our plans to expand our full service truck terminal business. I'm pleased to report that we've entered into a 50/50 joint venture agreement with a third party to develop a new full service terminal at Judy Creek. This is expected be in service by the first quarter of 2013, the new terminal will serve producers in the Beaverhill Lake and Swan Hills areas.

At Redwater West there's a lot going on. In the fourth quarter this year expect to have both our first of seven fee-for-service cavern storage facilities in service and plan to have the 8,000 barrel per day expansion of our fractionator on stream. On a much larger scale, our major projects team is advancing preliminary engineering work for a new 70,000 barrels per day C2 plus fractionator at the Redwater site, for which we are currently soliciting customer support. And, at the Younger plant we signed an agreement with a third-party producer to tie in up to 60 million cubic feet a day of production to the plant by the first quarter of 2013. So, in addition to these growth projects we have an unrisked capital spending program of about CAD4 billion that will focus on growing the fee-for-service component of our business. We are confident that we have the financial strength needed to pursue our growth plans. We're currently in a position of strong liquidity with cash and unutilized debt facilities at the end of the quarter of about CAD730 million, and our drip is raising approximately CAD22 million per month. And if our past is indicative of the future, we believe that Pembina should continue to have access to funds at attractive rates in the event we need to access the capital markets.

To close off the formal portion of this morning's call and turn it over to you for questions, I'd just like to reiterate that this was a very productive quarter for Pembina. Despite the challenging conditions for some of our business interests, we believe the first quarter of consolidated operations establishes a sound framework from which to tackle the second half of the year. We are confident in our dividend and confident in our ability to continue to identify and lock the value of the expanded asset-base. So with that I will ask the operator to open the call for questions and answers. So, over to you, Sarah.

(Operator Instructions)

Linda Ezergailis, TD Securities.

Thank you. I just have one -- I wanted to talk a little bit more about your dividend. Clearly, you're confident in the dividend level. But I'm just wondering what growth we might expect over the next couple of years given the commodity price headwinds you're facing? Might the Board consider pausing growth until your proportion of fee-for-service cash flow increased? And, when you look at a payout ratio, would a 70% to 80% payout of total free cash flow still be what the Board might be targeting? Or, might the Board more focus on non-commodity based or product margin based cash flows?

Linda, I'll just try to answer the several questions I think that with 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're going to change our growth targets or plans for the future. Obviously, in the near term, we've been impacted by the commodity price environment and that's had an impact on second quarter results for the NGL business unit. But longer-term, we've taken a look at the numbers and we don't see a 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 a lot. So, I think that we're going to stay the course with respect to the growth initiatives that we do have in front of us.

I'd have to say of the unrisked capital we have in front of us, Linda, that almost all of it -- I'd say and I think in fact it's fair to say, that all most all of it is related to fee-for-service business. So we will see the commodity related exposure come down over time, but it'll take us -- to spend CAD3 billion to CAD4 billion a year is going to take us four to five years too. So we would expect over time, that the commodity related exposed part of our business will come down.

And the other part of it we will have to look at as well is, where the commercial terms that we have in the commodity exposed business, as to whether there is an opportunity for us to look at the business model a little bit differently going forward. But it's still early innings, so I think we're going to stay the course and do what we have been doing and will adapt to the environment that we are in.

And the dividend policy, will that be adapted perhaps in the short term? Or does your dividend policy look at the long-term growth trajectory and not change in the short term in terms of growth rate?

Linda, we're still on the same course that we went on before. Our longer-term plans for dividend growth would have been in at 3% to 5% per year. I think it will be dependent to a certain extent on what happens in the commodity price environment. But I think that still remains. And payout ratios, 70% to 80% you talked about, I think our still 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 edition of butane strip pricing in 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'll take that under consideration, Linda.

Thanks, Scott.

Okay, thank you.

Robert Kwan, RBC capital markets.

Thank you. Bob, you touched on the strong liquidity that you've got right now. I'm just wondering though as you do look out at the funding plan and a cash flow deck -- at least at current commodity prices, probably come down versus budget. What are your thoughts on external funding specifically 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 the highest return projects?

Well you know, Robert, I think it's fair to say that we do look at all of our projects on the basis of those that are -- it's always will be combination. We're going to have some in the near term that are perhaps will generate what we consider to be modest returns but over time they'll generate more positive returns. And so we have all those projects underway and they'll vary from the Gas Services business unit to the Conventional Pipeline business unit to our Midstream and NGL business units and Oil Sands. And each of those businesses have different profiles and different risk profiles and different return profiles, but I personally like a well-balanced approach to it, Robert.

And in terms of financing, clearly, we look at it longer term. We finance our initiatives roughly 50/50 debt and equity. We've got plans to spend somewhere between CAD700 million and CAD800 million this year. The DRIP will raise just something in excess of CAD200 million. So I think that probably by the end of this year, early next year, we're going to have to be looking at some form of equity issue and that will be entirely consistent with where we were a quarter ago. I don't think our plans are materially changed as a result of some of the changing influences of commodity prices.

Okay. Maybe just the last question. With the potential reversal and repurposing of the Cochin pipeline, works quite well in terms of where they want to run that from condensate going into Redwater, as well some ability to move the propane out. Can you just talk about how you are 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 that?

Yes, there's a number of developments, some of which I can't talk about, Robert. So I'll just say that yes, the reversal of the Cochin pipeline will result in condensate getting up to Redwater. We see that's going to lead to -- it creates another source of condensate for oil sands supplies so that fits well with our overall strategy. But PENT, we are also developing PENT with a southern lays connection and other connections that we're also going to use that as a hub to launch condensate for diluent supply to oil sands related activity.

With respect to your question on moving other liquids out, I think it's fair to say that we, we're not going to sit idly by. I think that there's been a lot of changes that have taken place in the liquids market and we need to find other outlets for liquids out of the Fort Saskatchewan area, including looking at liquid moved to the west coast possibly. That's something that we'll also look at and consider in terms of go forward position. So, were looking at a number of things and will have a number of options to consider here. I think your observation is valid that the conditions are changing, they are changing in response to increased demand for diluent up in the oil sands. But also we have to find a way to get product out of Alberta to different markets as well.

Okay. That's great. Thanks, Bob.

Juan Plessis, Canaccord Genuity.

Thank you. As you mentioned in your remarks, Bob, you now have four-plus months operating the Provident assets. Going forward do you see yourselves making changes to the NGL hedging strategy? And, if so, what changes do you envision?

You know, Juan, that is under review currently. We have not entered into any new hedges in the last four months. We've unwound the one I referred to with respect to the oil hedge. I think it's fair to say we really want to get to understand the business and the business profile going forward before we really commit to a longer-term strategy. It's not to say they were not going to look at a hedging strategy. But right now I think it's fair to say that we want to understand the implications better going forward.

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're saying that we're 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've done so far is really just follow through with the program that was in place and approved by the Provident Board and we just want to get smarter about.

Okay, thank you. That's helpful. And with respect to the Redwater 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 cost of that project?

With respect to the level of contracting, right now, we reviewed it yesterday, Juan, and I think were saying quite a bit of interest. Probably in excess of 100% of the capacity. But I think that in terms of commercial commitments, I think we'd be pretty comfortable moving ahead at 50% to 60% of contracted capacity on that fractionator. I think there's a number of people that are waiting in the, if you like, in the weeds to see what happens there. In terms of capital cost, I think we've given broad guidance in the past. But I'd say that we're looking at something between CAD350 million and CAD400 million for a 70,000 barrel a day fractionator.

Okay, great. Thank you very much, Bob.

David Noseworthy, CIBC.

Good morning, gentlemen. Just wanted to better understand a bit what happened in the quarter in terms of Midstream sector and what we're looking at going forward? Historically, your gas supply has been contracted, I believe, like on a one-third, one-third, one-third basis spot, monthly, and long-term. Has this changed materially?

I don't believe it's changed materially during the quarter. Although I think the spot market probably is not something that we've been focusing too much on at this stage. One of the issues we've got, David, is that we don't have a lot of place store any of the production that we can generate. We're 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.

Okay. And, is that the situation both in Corona and Redwater?

Yes I think that applies to both.

Okay. So then when you speak of the extraction premiums reflecting a longer-term, higher, longer-term frac spread. So that would be more on your long-term gas supply contracts, 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?

Yes I think we've seen the spot come down. More recently the problem we have is that we can't really take advantage of that lower priced spot market because again we don't have any place to put the product.

Okay.

David, I don't think that dissimilar to a lot of people at this stage. I mean, we're long NGL in North America. And that's until the market clears through either increasing demand -- and we are seeing that, the more recent increase in the price for propane, I mean that's a positive development. I think our people also think that there's going to be a fairly significant increase in export capacity out at the Gulf Coast here in the next 12 months, which should help alleviate some of the over supply as well.

Appreciate the color. In terms of when we look at your result in trying to compare on year-over-year basis. On a percentage basis how does the Provident's old commercial segment operating margins break out between Redwater West and Empress East?

I don't have that level of detail. Maybe Scott, you want to answer the question?

About 25% to 35% of commercial services is in Empress East.

Okay. Perfect. Thank you for that. And then finally in terms of the Alberta ethane prices, have they recovered at all with the completion of the turnaround at Nova and [Idaho]? What are you seeing there?

You know, David, I don't know specifically. I do know that as a part of our overall program to offer services to our customers that we are working with the people in the petrochemical business for them to offer up long-term commercial contracts to our customers at prices that are going to be acceptable to them for 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 backstop capacity additions at their facilities.

That fits very well with our overall strategy of dealing with all the products that come under the NGL business, because we don't have any control over what happens with ethane and ethane pricing. But if their customers can get into long-term contracts, that fits very well with the overall service we are going offer.

And, producer inclinations so far has the positive towards wanting to extract the C2 plus mix, because of these contracts?

I think that's a fair comment, yes.

Okay. And maybe just one last question. There was a mention about looking for new markets for some of these NGLs. In terms of -- what is your, Pembina's capacity to produce waterborne quality export or export quality propane at Redwater?

Currently -- I'll turn that question over to Bob Locke.

David, thank you. Yes, we're looking at that certainly. So we're producing product qualities that's not at this point waterborne, but it's typically water quality or water content in the propane that we'd be looking at taking out. So as we expand our own proprietary view of what might be out there for options for us, we'll be looking at putting additional treating for that.

And do you have any idea at this point what equipment that would take or CapEx that would be required?

It's early days for that, but we're looking at those options. It really comes down to what volume it is we're looking for.

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

It may.

Okay. Well thank you very much, gentleman. Those are my questions I'll get back in the queue.

Carl Kirst, BMO Capital.

Thanks, good morning, everybody. Most of my questions have been hit. Maybe just a couple of cleanups. And first actually, perhaps starting on the BC market as far as potentially moving liquids west, and we generally tend to think all about propane export right now. Is there a possibility of doing other waterborne product export? Or would the market for the West Coast really principally just be a propane one?

You know, I think, Carl, that it would primarily be a propane one. When you look at the liquids that are produced, condensates going to be consumed in Alberta. The butane will likely be consumed in Alberta, the ethane will be likely consumed in Alberta, so it's really the property market which would try to find a market likely elsewhere.

Great. Appreciate that. 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, with that portion that is term supply, what is the tenure of that? Is that something that, we think of the contract year basically being April to April perhaps with the rest of those contracts roll off by April of 2013?

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

Carl, I can answer basically half 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 1 deals. So they would have an expiration profile of November 1 to October 31 of every year. As it comes down to breaking up how much of our portfolio would have on the month-to-month, the seasonal, the annual, or the daily options that are out there, we don't really disclose that. So the pricing specifically to those terms are not currently available.

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

No, understood. But it sounds like then that whatever out-of-market extraction premiums we are paying right now, hopefully that will be alleviated soon, then?

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

Exactly.

That's a fair question, Carl. Yes.

Thank you so much.

[Matthew Hayman], Scotiabank.

Good morning, everyone. Thanks, Bob. Obviously you guys didn't buy Provident primarily for Empress. Having said that, I am sure you expected it to make a positive contribution. I guess to what degree were you surprised by the extent of swing that could occur there? And what have you learned in the last few months of in terms of how to at least get it profitable and to avoid this extreme results?

I think, Matthew, that's a really good question and I have to say that we're learning as we go here too. I think the circumstances during this second quarter, and particularly during the month of June, were not expected. I don't think expected by anybody when you look at the decline in the commodity price. Some of the product production was hedged, but obviously not enough. I think looking forward, we're looking at Q3 or Q4 as returning to fairly solid contributions from Redwater and Empress, in response, really to 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, as you eluded 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'll be more to come. So clearly our view is longer-term. I've had Scott look at dialing forward the results over the next three to four years on assumed lower commodity price environment. But you know what? It's still doesn't look that bad. In fact it looks very good. And the projections that we have been public with, I'm 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 been formerly successful didn't do so hot in the quarter either. I mean Spectra didn't really make money there. I imagine Plains is looking at this with a new view. I mean, there's got to be a feeling among the Empress guys, we're not going to pay this level of premiums anymore? Is that your sense of the consensus among the Empress owners?

I've personally have not talked to a number of them. I know I do have some conversations that are going to be coming up here actually with respect to Empress and what needs to done there. I think that it's fair to say that there's excess capacity at Empress. There's processing capacity of something like 12 bcf a day with about 4 going through it. So obviously there's excess capacity and people chasing it quite competitively. Perhaps there should be a rationalization at Empress. And I think that's something that needs to be discussed further. But at this stage is the conversation. And some people, they 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.

Yes. I guess my final question, you touched a little bit. But I wanted to ask more directly, which is on your hedging policy. I'm sure your 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 hedged at all. Interpipe, I think, is going to hedge less, because fee-based is outweighing commodity-based cash flow. And I think that's the same as Pembina, as you guys grow. Is not hedging at all, these frac spreads, an option that might be on the table going forward?

I think, Matthew, all of the options on the table, including that one. That's why I think, like I said, we want to spend some more time understanding it. We've got some legacy hedges that were in place in Provident that 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'm not big on hedging, but there could be a scenario here where it does make sense. I'd say that longer-term, to the extent that the commodity exposed part of our business gets less, I'd be less inclined to hedge.

Okay. Thank you very much. Those are my question.

Robert Catellier, Macquarie.

I just wanted 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 yourselves are one of the more efficient plants. And if I take Scott's comments of 25% to 30% of the commercial revenue at Provident being allocated to Empress, doesn't look like Pembina made any money on the frac spread business at all. The implications there that the extraction premiums have to come down because nobody's making any money.

Yes I think, Rob, that's a fair comment. I would agree with that. That if you're not making any money, why do it? That's the business. We've got to do a fair amount of naval gazing here to see what makes sense long-term.

Getting out beyond that for a minute on the propane side. There's the export capacity that's getting built up. I'm wondering if the Murray or the Company has a view on assuming a normal linter, how long does it take the propane market to rebalance, given the increasing export capacity?

The sense I got, Rob, with respect to that is it's going to be like somewhere 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 will draw about 3.5 million barrels. So we 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. I say while it's early innings, we're saying realistically Q1 of next year.

And then to further the hedging question a little bit. Obviously there's frac spread and then there's marketing. Does the current Provident strategy that your running with now until you make your evaluation, does that hedge any of the marketing exposure at all?

I can't answer that question, Rob.

This is Bob Lock. 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 when you evaluate the plan, I know you're obviously not finished, but is the preference to stick with -- are you more concerned about the frac spread or the marketing in terms of what you might -- where you might consider hedging?

You know what, Rob? I'm saying that we're going to study that pretty hard here right now. And like I said, unfortunately -- it's not like we didn't know it, but we do have a legacy positions here that we have to get our way through. And we're going to be through those in 2013 and I think that we can take a fresh look. We can take a fresh look before that, as well, but it's going to take the next few months to really sort our way through that. But I'd be interested, as we've talked, you've got some of your own personal views and I think we like to explore some of your thoughts on the subject as well. Because, as I say, this is a bit new to us and something that we want to fully understand before we can make any commitments.

Okay. We'll obviously bring that off line. But the other part I noticed on the updated hedging guidance, there's a mismatch between the percent of NGLs hedged and the amount of gas hedged, so you're more hedged on the gas. And that creates a bit of a basis risk. So maybe you can just talk about what exposure you have then to those changing dynamics?

Well that's part of the legacy situation I discussed, Rob. That there was a higher percentage of gas that was hedged, hedged historically. And gas volumes have come down as well. So we're probably 80% hedged on volume, which isn't necessarily where we believed anybody wanted to be. So that's got to sort itself out in time so there's a proper balance between the gas and the products.

Okay. And then my final question is, just a housekeeping, Provident formally had maintenance capital reported whereas Pembina was effectively expensing everything. So what happens to -- how are we to view the maintenance capital requirements that Provident had previously? Are those now being expensed?

I'll let Peter answer that question.

Yes, I gather these are fairly small amounts for the second quarter. If they were capitalized before, they will continue to be capitalized. For the quarter, it's only about just over CAD2 million for the quarter, and I would expect for the year, assuming nothing has changed in how we categorize that maintenance capital. I would expect CAD8 million to CAD10 million for the nine months for 2012.

And Peter, I'll ask you this question. Our intention is-- would we capitalize that or --?

Maintenance capital, as you know, is not a GAAP measure. So how we define it is very subjective. We really have to see if additional capital is -- do we get additional revenue out of this additional capital? Certainly on our legacy assets, if we spend capital on our Conventional Systems then generally that additional capital attracts a toll in the following year. So we view that as development capital. The Provident assets, maybe a little bit different if we can't get additional revenue on those small amounts of capital.

Right. So the message is keep on with the modeling we had previously with Provident until you tell us there's change in the treatment?

Yes, I think that's fair, Rob.

Okay, thanks.

Steven Paget, FirstEnergy.

Good morning and thank you. Just noticing your Oil Sands net operating income is off a bit versus the first quarter. I'm wondering if you could let us know the drivers behind some of that?

Yes. I think on the Nipisi, Mitsue pipeline, Steven, we were slightly off on our take-or-pay commitment. So that resulted in lower operating income for the second quarter compared to the first quarter. I think the situation has been rectified with -- it really had to do with the ground temperature conditions that impacted the amount of product we can move plus a change in diluent specs. So those things have bee pretty much behind us. We expect the third quarter to return to more normal operations for the Nipisi pipeline.

Thank you. You mentioned that both Corona and Redwater are full. Would it make sense -- or maybe you are doing this already, to be moving out NGLs in any and all ways possible, whether it's rail -- or I guess truck is probably not economic, but moving things out by rail to the Gulf Coast?

I'll let Bob Lock answer that question.

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

Okay. Thank you. And how should we be looking at third quarter volumes at Empress East and Redwater West given the fullness of the storage?

So again, I think our tight spot here for containing supply is the summer months, because us along with every other player in the storage business for propane started the summer with higher than average inventories. So once we're through that, our expected sales profile should be very similar to our historical performance.

The only comment I guess, Bob, we have a fractionator expansion underway and Redwater, is that going to impact our production for September?

So, Bob's right. We're undergoing a debottleneck project at Redwater for about 8,000 barrels a day. And we expect that to be online for October. So it won't have a tremendous impact on the third quarter, on the fourth quarter we'll be having more product available.

Okay, thanks, Bob. So, I guess ignore the last part of that conversation, Steven.

Okay. So third-quarter for production volumes looks pretty good then?

Yes, it's comparable to the past.

Comparable to the past. Thank you.

(Operator Instructions)

David Noseworthy, CIBC.

Hello, gentlemen just a few questions here on the Oil Sands. We've seen some recent announcements by IPL and TransCan regarding the Oil Sands pipelines and dilbit pipelines. Can you talk about what you see in terms of a need for additional Oil Sands dilbert and diluent transportation capacity over the next two to four years?

What we can see. Not withstanding there's been announcements, David, that there's a number of different areas that require service in the Oil Sands. And so we're still looking at diluent supply and dilbit return to areas that we're familiar with and I think we'll have more to say in time. But we still think there's going to be sufficient demand. One of the advantages that we have now through the Provident acquisition and development of our storage facilities, is sourcing diluent from a number of different places that will be very attractive to customers or potential customers in the Oil Sands area.

So that leads into my next question. In terms of providing logistics contracts, we've seen with the Corolla project, one of your competitors there, tied up a diluent logistics contract. Do you see an opportunity on the expanded Polaris pipeline to provide something similar?

I really can't comment on that.

Fair enough. Okay. And then finally, just on Younger, for the capacity I think it was 60 MMcf per day that your expected to see there. Would that additional capacity require any capacity expansion at Younger?

No.

Okay, Fair enough. Thank you very much.

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. Obviously there's a lot of interest in what's going on in the NGL business and we're quite interested in that as well. We're learning as we go, but we're still very optimistic about what the Provident transaction will mean to us. We're still very positive on all the projects that we have and our views haven't changed there. So we'll have more to say as we progress through the next couple of quarters. We're pretty optimistic about what the future looks like. Thanks for participating this morning and if you've got any other questions, you can talk to Glenys or Scott or Peter, because I'm going to be away for a week. So long.

This concludes today's conference call, you may now disconnect.