Pembina Pipeline Corp (PBA) 2013 Q2 法說會逐字稿

Good morning. My name is Tiffany and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation's 2013 second-quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Bob Michaleski, CEO, you may begin your conference.

Thanks, Tiffany. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our second-quarter 2013 results. I'm Bob Michaleski, Pembina's Chief Executive Officer. Joining me on the call today are Mick Dilger, President and Chief Operating Officer; Peter Robertson, Vice President of Finance and Chief Financial Officer; Scott Burrows, Vice President of Corporate Development and Investor Relations. For this morning's agenda, we will follow our standard process. I'll spend a few minutes reviewing our second-quarter 2013 results, which we released after markets closed on Friday, provide an update on Pembina's recent developments, and then open up the line for questions.

I'd like to remind you that some of my comments 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 provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see Pembina's various financial reports, which are 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.

Now, both our financial and operating performance during second quarter and first half of 2013 were very strong. Since acquiring Provident, this is the first quarter that shows fully comparable or apples-to-apples result. I'm extremely proud to say that Pembina has successfully delivered on a promise to increase shareholder value through maximizing our asset base and strategic growth, which is evidenced by our improving quarter-over-quarter results and the dividend increase we announced on Friday. Our new monthly dividend rate will be CAD0.14 per share or CAD1.68 annualized. This 3.7% bump, which is effective as of August 25 record date, reflects our confidence in the Company's solid fundamentals, growing and sustainable cash flows, and fee-for-service-focused growth plans.

Our accomplishments once again demonstrate Pembina's ability to deliver on what we say we will do while showing we have the capacity and capability to execute large-scale value-added growth projects in the future. Overall, we benefited from strong performance during the second quarter in our Midstream business, which was supported by improved propane markets, in addition to the increase we saw in volumes on our Conventional and Oil Sands Pipelines, as well in Gas Services due to increased customer activity. Pembina's integrated service offering, our continued investment in our businesses, and the strategic location of our assets allow us to continue to realize improved performance.

In the second quarter, adjusted EBITDA increased by 47% to CAD185.1 million from CAD125.9 million in the second quarter of last year. Across-the-board, we saw increased performance in each of our businesses during the quarter. Year-to-date, adjusted EBITDA totaled CAD395.3 million compared to CAD237.3 million in the same period of 2012. Moving on to adjusted cash flow from operating activities, we saw an increase of 61% compared to the second quarter last year. On a per-share basis, this equates to an increase of over 51% and was largely due to improved results from operating activities in each of Pembina's businesses. For the first six months of the year, adjusted cash flow from operating activities increased by almost 87% and almost 40% on a per-share basis compared to the prior year.

Since we did see increases in all of our businesses, let's now look at the performance of each. For our Conventional Pipeline business, average throughput increased by 11% during the quarter and by 8% in the first half of the year compared to the same periods last year. Strong volumes and asset transfer from our Midstream business and modest tariff increases on certain of our pipeline system brought total Conventional Pipelines revenue in the second quarter to CAD101.5 million, almost 30% higher than revenue of CAD78.4 million in the same quarter of the previous year. On a year-to-date basis, revenue increased just shy of 30% from CAD160.6 million in the first half of 2012 to CAD197.3 million in the first half of 2013. Offsetting higher revenues in Conventional Pipelines was OpEx, which increased about 25% for both the second quarter and first half of the year compared to the same periods of the prior year. These increases were largely because our ongoing pipeline integrity program, as well as additional expenses for power and labor.

Second-quarter operating margin was 38% higher than in the same period of the prior year and approximately 24% higher than for the first six months of the year compared to 2012. Our Oil Sands and Heavy Oil business generated better results during the second quarter of 2013 than in the second quarter of 2012. This was because of higher recoverable operating expense across the business systems and throughput beyond our contract's capacity being transported on the Nipisi Pipeline. As a result, our operating margin for the second quarter and first half of 2013 increased about 17% and 11% compared to the same periods of last year.

Gas Services has also seen increased throughput with the Cutbank Complex processing average of 290 million cubic feet per day during the second quarter and 295 million cubic feet per day in the first half of 2013 compared to 285 million cubic feet per day in the second quarter and 275 million cubic feet per day for the first six months of 2012. These increases reflect the sustained interest of producers and more specifically our customers in the areas surrounding our Gas Services assets and their push to extract liquids from the liquids-rich NGL, which is still attracting higher commodity prices relative to dry gas.

Higher processing volumes, increased fees for additional capital we invested at Cutbank Complex, and a greater recovery of operating expense bumped our revenue in this Business by almost 29% and 36% for the second quarter and first half of the year. Offsetting this revenue increase were higher operating expenses, which were largely the results of the labor and power costs associated with higher volumes and increased activity at the Cutbank Complex, as well as additional expenses related to running the Musreau shallow cut expansion and deep cut facility. Overall, operating margin in Gas Services increased about 16% and approximately 29% for the second quarter and the first half of 2013 compared to the same periods last year.

Lastly, let's take a look at Midstream. This is the first reporting period where we can draw a true comparison between a given period in one year and the next. As a reminder, the assets we acquired from Provident are reported in our Midstream business and we didn't own these assets until April of last year. Our NGL Midstream activities had a very strong quarter. Operating margin for the period increased approximately 134% compared to the same quarter of last year. And NGL sales volumes during the second quarter of 2013 were 94,000 barrels per day, a 4% increase compared to the second quarter of 2012. This increase was driven by higher sales in propane, butane, and condensate.

Our Redwater West assets, in particular, benefited from the stronger propane market and increased sales volumes for condensate, bringing in an increase in operating margin during the second quarter of about 23%, excluding realized losses from quantity derivative financial instruments. Similarly, Empress East operating margin benefited from stronger propane markets and condensate sales. Here, operating margin increased significantly during the second quarter of this year compared to the same period of 2012 from just over CAD2 million in 2012 to almost CAD16 million in 2013.

Now, moving to our crude oil-related Midstream activities, operating margin decreased about 9% during the second quarter of 2013 compared to the same period last year due to narrow price differentials resulting in fewer storage opportunities and lower overall margins. On a year-to-date basis, though, higher volumes and increased activity on Pembina's pipeline systems, robust demand for diluent services, wider margins in the first quarter of the year, as well as increased throughput at the crude oil Midstream truck terminals, resulted in increase in operating margin of almost -- about 17%.

As I noted on last quarter's conference call, some of the opportunities we were able to take advantage of take advantage of during the first quarter of the year and which drove such strong first-quarter results are not typical, especially with respect to margins in certain storage activities, and we've seen in this business normalize a bit through the second quarter. On a consolidated basis, the result of our businesses were very positive. This is especially true when you consider that the second quarter is usually the weakest for a couple of reasons, including planned producer turnarounds, which typically effect production rates and softer propane markets, due to the seasonal inventory build throughout the spring and early summer.

I'll now move on to provide you with an update on our growth projects. During the first six months of 2013, Pembina has secured approximately CAD1.5 billion in capital projects, which will help provide long-term and sustainable returns to our investors once complete. It is as significant to note that the Cornerstone Pipeline project and Pembina's open season are above and beyond this number. I'll go over each briefly and we can talk more about them during the Q&A if you have specific questions.

Starting first with our Oil Sands and Heavy Oil business, on June 27 of 2013, Pembina announced that we executed a CAD35 million engineering support agreement with the KKD Oil Sands Partnerships or KOSP, in which Statoil is the managing partner. This agreement is to progress our negotiations related to building the Cornerstone Pipeline system. The new pipeline system would service as KOSP's enhanced oil recovery development and would transport diluent and blended bitumen between Northeasterm Alberta and the Edmonton area. The proposed pipeline system, which is subject to Pembina and KOSP reaching satisfactory commercial arrangements and obtaining the required environmental and regulatory approvals, is estimated to cost CAD850 million and could be in service by mid-2017 based on preliminary design work.

Executing the ESA is great news for Pembina. It moves us closer to finalizing a long-term agreement with KOSP for the construction and operation of a potential new Oil Sands project. Under the ESA, we will be progressing engineering work and stakeholder consultation. The Cornerstone Pipeline project, should it proceed, will also bring us other integration opportunities and synergies, especially for Pembina's Midstream business. This includes shipper opportunities as Pembina expects to take 50% of the capacity on the diluent pipeline.

In Midstream, we continue to see many growth opportunities in the Midstream space beyond those associated with the potential Cornerstone Pipeline. In fact, we recently announced that we are investing about CAD65 million at our Redwater site for a new service cavern for NOVA and associated facilities and upsizing some of the infrastructure associated with our Redwater II fractionator to potentially expedite the development of a third facility at the site. During and subsequent to the second quarter, we also completed and brought on stream several projects including three underground hydrocarbon storage caverns and a new full-service truck terminal. And we completed our crude oil [rating] loading facility, which we expect to have up and running in September.

In the midst of all of this, we are still actively working on the development of a propane export project. This is perhaps taking longer to get off the ground than we initially expected but we are confident that there is an international market for Canadian propane and that Pembina is well-positioned to help provide the solution. Turning now to new developments in Gas Services, we were very excited to announce last Friday that we are pursuing a new 100 million cubic feet per day shallow gas plant and associated NGL and gathering facilities, Musreau II, located near our existing Musreau facility. The facility is expected to cost CAD110 million and 100% of the operating capacity is contracted under long-term agreements. Musreau II will be equipped to handle propane-plus and is expected to yield about 4,200 barrels per day of NGL for transportation on Pembina's Conventional Pipelines. Pending all regulatory and environmental approvals, the Musreau II facility is expected to be in service by early to mid-2015.

With respect to our previously announced projects, construction of the fully contracted Saturn I and Resthaven gas plants are both on track. We expect to bring Saturn I online this month, a quarter ahead of schedule, and the Resthaven facility should be in service during the third quarter of next year. You will note that we revised our capital spending estimate for Resthaven in our quarterly report. We are now expecting the project to cost approximately CAD240 million versus our previous estimate of CAD210 million. This increase is due to redevelopment of certain aspects of the facility and scope changes. We are currently in discussions with the customers with respect to the associated fees. Our Saturn II facility is also progressing as expected.

As for our Conventional Pipelines and our expansion plans, we brought an additional 17,000 barrels per day of NGL capacity on stream in June and expect to see a further 35,000 barrels per day coming on stream by the end of October of this year. This will complete our phase I NGL expansion, but of course we still have phase II to finish. The two expansions together will see our NGL capacity on the Peace and Northern systems increase to 220,000 barrels per day by early to mid-2015. Moving now to our crude oil and condensate expansions, in July, Pembina brought three pump stations into service and expects to bring the remaining two online by October of this year, which would complete the Phase I expansions and add another 40,000 barrels per day of crude oil condensate capacity on Peace Pipeline. The Phase II expansion is also in progress and we are now into detailed design and engineering. We expect the regulatory process to go quite smoothly on this project. Once Phase II is complete, our crude oil and condensate capacity will reach 250,000 barrels per day by late 2014.

Now, as announced in April, we have also completed our non-binding open season to assess demand for transportation in the northwest region of Alberta. We are now in the process of stakeholder consultation, advancing third-party engineering design analysis, and commencing negotiation of mining transportation agreements with area producers. Finally, I'll cover off a brief overview of our financing activities in 2013. Since the beginning of the year, we were able to execute three successful financings, demonstrating our ability to access capital as the market recognizes future value in our suite of development projects.

Maintaining a strong financial position plays an important role in being able to execute these growth projects and, as such, raising these funds is a testament to the belief our investors have in our strategy. To this end, in late July, we closed our inaugural offering of preferred shares for gross proceeds of CAD250 million and issued CAD200 million in 30-year notes in April. We also raised CAD345 million in equity in March of this year. Now with only CAD105 million drawn on a CAD1.5 billion credit facility at the end of the second quarter, Pembina remains well-positioned to continue to fund our growth plans going forward.

In closing, you can see that Pembina realized strong operating and financial results during the second quarter and the first half of the year, which is evidence of our ability to continue unlocking the value contained within our integrated service offering. This service offering, our ability to lever its existing assets, and our proven track record of completing capital projects, have positioned us well to capture market share in our operating area going forward and have led to a growing dividend. In total, Pembina has paid over CAD2.7 billion in dividends or approximately CAD19.64 per share since inception in 1967.

With that, we can start the Q&A. So, Tiffany, please go ahead and open the line for questions.

(Operator Instructions)

Linda Ezergailis, TD Securities. Your next question comes from the line of David Noseworthy with CIBC.

Congratulations on a great quarter. A lot going on. So maybe I'd like to start off with some of your growth project updates. In particular, can you tell us a bit more about the CAD65 million Resthaven scope and design change? And how Pembina expects to recover on those capital costs? And perhaps how those returns on the incremental capital compare to those anticipated on the original CAD175 million?

So, David, the CAD65 million was with respect to a couple of projects. One of the projects was with respect to potentially spending capital right now in anticipation of the possibility of a third fractionator at Redwater. So, what we're doing is just really -- it's, a lot of it is just ensuring that we've got adequate pipe size available to handle the potential volumes from a third fractionator, which is going to cost us somewhere around CAD25 million to CAD30 million, roughly in that range. And so the other capital is related to other activity at Redwater. In terms of anticipating how we're going to recover that cost, it would be associated with the commercial arrangements we make ultimately when we get to build a third fractionator in Redwater.

Thank you for that. And maybe the other I was wondering about was just Resthaven, I noticed the new capital cost was CAD240 million. And originally it had been CAD175 million. And so I was just looking at that. That also happens to be a CAD65 million delta?

Yes, sorry David, again, what I should explain is that the original engineering was done by one of our customers in -- for the Resthaven facility. And when we started getting into the details, it was obvious that things had changed. So, we actually had to almost re-engineer the project. That resulted in the increase in costs as well as the fact that it looks like a lot more of the volumes that are going to be coming to that facility will have higher liquids associated with them so that required, again, a scope change. So, we are in the process -- this week we expect to conclude negotiations with the customers with respect to increased fees associated with the increased capital and we expect to be able to maintain our economics on that project.

Okay. Appreciate that. And then in terms of your -- the new announcement with Musreau II, can you share with us who is backstopping that plant?

I'm not sure if the commercial ranges are confidential. They are area producers.

I think we should wait on that.

Okay.

That's fair. David, that would be -- we've got -- there are four customers that we have that are producers in the area and I don't know that we are in a position to be able to disclose who they are.

Fair enough. And perhaps more of a big picture question, can you provide your perspective on the development of Gas Services in Western Canada? And beyond your 1.2 bcf that you already have in operations or under development, how much more demand do you see for third-party field gathering and processing over the next, say, three to five years?

Well, as a part of -- what we're calling our Phase III or [eco]-project for pipeline service, David, we're certainly learning that a lot of customers are in need of processing in addition to pipeline as well as -- when I say processing, that's processing in the field to handle liquids and then pipeline transportation as well as fractionation so from our perspective, we say that the potential is significant going forward over the next three to five years for future development of the gas processing facilities as well as the pipeline and fractionation facilities.

And then just to get a feel for quantum, is it -- could we see -- is it 50% of what you have today? In terms of blue-sky broad numbers, what demand are you seeing there?

It can range. And I'm going to say that -- right now, we're moving, say, about 0.5 million barrels per day and that we could see that easily doubling by the end of the Stage III expansion.

Right on. And one last question on your LPG export terminal development, what's causing the delay of the development in that process?

Well, you know what? This is new business for us and we were working with one customer who had perhaps different interests than we did. And to that process, that we learned that there will likely be very high demand for propane being exported out of Prince Rupert. So our approach that we're taking on now is to determine who is going to be interested and who is willing to commit. And that really is something that's important to us. Also, we are wanting to ensure that we had an adequate location for a facility. And we've made good progress there as well. So it's all been -- it's been pretty much as expected under the circumstances. And we're pretty optimistic that we're going to have a pretty good project here that we will talk more about by the end of this year.

Perfect. Well I'll look forward to that. Thank you. Those are my questions. I'll get back in the queue.

Juan Plessis, Canaccord Genuity.

With respect to the capital spending for the potential Redwater III project, what would be the capacity of that plant if it went ahead?

If it's going to be a C3-plus facility, it will be about 50,000 barrels per day.

55,000.

55,000 barrels per day. We'll build the same -- we intend to build the same unit as Redwater II. But perhaps hold off on the ethane extraction for now. It will depend on downstream markets whether there's an ethane extraction there or not.

Okay.

So if there is ethane it will be 73,000 and if there is not it will be 55,000. That's the plan anyway.

Yes. Thanks.

Okay. Great. And you took over operatorship of the Resthaven plant from Encana. Is this a permanent change and are there any synergies that you think you can derive from this?

Yes. It most certainly is a permanent change. And in fact, the Resthaven plant, as it's known today, won't exist anymore. It will become part of the new Resthaven plant. So we're actually using equipment from the existing facility for the new facility.

And in terms of synergies, Mick, did we see any synergies there -- it's already -- we're taking over operatorship, we've hired their staff.

Yes.

And we'll continue to operate essentially as they have. I don't think there's going to be any obvious operating synergies because it's essentially a standalone facility.

Yes, and there will be capital synergies, because we're using existing equipment.

Yes.

Okay. Thank you. And just finally here, with respect to the Northwest Alberta Pipeline expansion opportunity, can you talk about the scope of the potential expansion both perhaps in terms of capacity and projected capital costs?

Well, at this time, Juan, it is an iterative process, in a sense. We've been conversations with probably, I'm going to say, 25 to 30 producers to date to try to assess their requirements. And at this stage, it's a little too early -- my response to the question from David Noseworthy was to say that we expect to have at least 0.5 million barrels a day of product to move under that but it could be more than that and in terms of cost you're talking anywhere from CAD1 billion to CAD1.5 billion, that's just pipeline related and there will be other facility additions that will be necessary in the processing area, gathering lines, new connections and so on. So the project, in terms of scope, can be fairly significant here. In total we have had 58 area producers talk to us about their requirements and we're now in the process of going through the details with all of them.

That's great. Thank you very much.

Carl Kirst, BMO Capital.

Congratulations as well on the results in Musreau II. Just following up perhaps on the Alberta -- the Northwest Pipeline. One, should we be thinking of this as -- well, let me reverse order perhaps. As we look at spending more money to increase the fractionation for Redwater III, would that be something that we go hand-in-hand with something like the Northwest expansion? Or should we be keeping those -- the advancement of those two product projects separate?

No. They should be looked at together, Carl, because that's really part of the integrated strategy that we do have. We're talking to people about gas processing, liquids extraction, liquids transportation, fractionation, marketing. And that's the story. Customers, they understand that story and they quite like it, actually, that's their preference.

And so, to the -- I'm sorry, so to the extent that you're spending more upfront here to build in the capacity for ultimately RFS III, obviously that should be underscoring your optimism of where you think the broader project is headed?

Yes. That's fair, Carl. Mick, I don't know if you had anything further to add?

No. That's all.

Okay. And then lastly if I could just -- I understand it's early days, but given perhaps the early read through the non-binding open season, is there a sense of timing on when something of this type of size come together? Is that a -- through the iteration -- is that a six-month process? Is that a 12-month process? And understanding this has its own life and can move around but just as you sit here and look at it today, is there any timing expectations?

Yes. Mick has got some thoughts there.

The way I would think about it, we've announced Phase I and then a year later, Phase II. And this is Phase III-A. It's going to be a continuous series of expansions leveraging off what we have already. I don't think it's going to be turn on the switch and get 0.5 million barrels a day. It's going to be 40,000, 60,000, 80,000 barrels a day and in -- on different timing and so we'll probably keep announcing expansions over the next number of years rather than a single block of volumes.

Okay, no, that's very helpful.

Yes. Carl, what we're hoping to be able to accomplish -- the conversations are taking place now. But, as Mick has said, that it looks like there could be different levels of expansions, but we are hoping that by the end of the year, we're certainly in a strong position to be able to communicate to the market what we think this project will look like. As you can obviously tell, Pembina is feeling pretty confident about where we are in this project with right now with our front-ending of the RFS III and accelerating some of the work on right-of-way and so on for the pipeline.

Great. Thank you. And actually one clarification of something, Bob, you said earlier, in talking about the potential propane export, I know you're working with or you said you were working with one potential customer but who may have had different interests, are you still working with that same customer today or have you moved on now to other or a broader range of customers potentially?

It's fair to say, Carl, we are moving to a broader range of customers -- a broader range of customers. That is a customer we had been working with, would likely still be a candidate. But not for the same commercial arrangement that we were thinking about initially.

Great. Thank you for the clarification. Thank you.

Matthew Akman, Scotiabank.

On Empress, you guys are making money there. Volumes were low and gas flow there and frac spreads weren't great. So that's a nice result. I'm just wondering what you're seeing there generally in terms of the dynamics and how you've turned that around?

Well you know what? Matthew, when you're making money, that's a good thing obviously. The propane market in Eastern Canada was strong through the first half of this year and propane inventories continued to stay low. So, if we have a typical winter, we expect Empress to continue to produce positive results for Pembina. In terms of other activity, in terms of rationalization of ownership and so on, conversations still are taking place, Matthew. But I don't think there's been a lot that's transpired here. We're continuing to try and source the product we've acquire out of Empress and still have -- generate profit of positive results so we're pretty optimistic about what it looks like for the second half of this year and the first half of next year.

Our volumes -- our Empress flow is all around being soft. We're maintaining our throughputs down there so our market share is over time actually increasing and that's simply because we have the most modern, lowest-cost plant so we hope that trend can continue.

Good. I wanted to move to pipeline integrity. Expenditures. This is a year where you guys are probably spending more than you have before. Some tens of millions on it and it's also critical in light of the focus on safety and environment and also the expansions you are undertaking. Could you please update us on how that program is going? What you're seeing in terms of integrity of this existing system? How the system looks overall? And whether there's any surprises, positive or negative?

Matthew, the dollar amount of the expenditures on integrity clearly are increasing and that's what we expect. We expect them, actually, probably to stay at this level next year, but there haven't been any surprises. These are things that we're just doing, we are increasing the testing, we are going to be running at higher pressures so we have to ensure that the pipeline is going to be certified to run at those higher pressures and so far so good. We really haven't found anything that's caused us any concern about the integrity of the pipe itself. So it's business as usual for us, but it does mean that we do to continue to front-end these expenditures in advance of new volumes coming to the system.

Good. Thank you very much, guys. Those are my questions.

Robert Kwan, RBC Capital Markets.

Just maybe to start on dividends, how would you characterize the increase you've had? Was it more on the back of the strong results and confidence in the future? And also if you can just frame that against any thoughts against a regular dividend increase policy? Is this the time of year? Will you be looking at something else either with Q4 or Q1 results?

Well, Robert, in response to your first part of your question, the Executives here in this room are pretty confident with respect to what the future looks like for Pembina, particularly in light of all the projects we are working on today, and in some cases projects that we continue to work on, so, clearly that's the case. With the guidance we provided Robert, in the past -- I'd say last year, has meant to suggest that dividend increases in the range of 3% to 5% per year we think are sustainable. In terms of timing, normally -- because we're fairly conservative -- normally, we would wait probably till the third quarter of the year at the time we are working on our budget and so on. But we also do projections, we do five-year projections based on projects we have in front of us. So, I think that we're pretty comfortable obviously in making the dividend increase this year.

And then what we have to decide is are we going to have a sustainable annual dividend increase. We're feeling pretty comfortable with that. Will it come in one or two tranches? We haven't decided yet. So right now we're saying, the guidance we've provided 3% to 5% per share per year is pretty doable. I think that it's something that the market hopefully will get to expect, which is similar to what we've done in the past if you look at our historic dividend increases they've been in that 4% per share per year.

Okay. So just to be clear with that, 3.7% within this 3% to 5% range, based on everything you're seeing, we should be expecting probably another increase in 2014?

Yes.

Okay. That's great. Just coming back to Musreau II, I know you don't want to get in to any specifics with respect to your customers. I'm just wondering as a group of those four, can you just give some general thoughts on why they went to the shallow cut versus the deep cut? Was that really just a function of where the NGL pricing versus the capital cost was?

It's more of a function of available fractionation capacity. And at this time, it's very tight. And as you know our Redwater II is full and we understand many or all of our competitors are full and so until another ethane fractionator gets constructed, we'll probably see more either shallow cut or deep cut plants with ethane rejection capability built.

That's great color, Mick. Are the volumes from this plant going to be going to Redwater?

Some of them are, yes.

And just with it being a C3-plus mix versus your C2-plus fractionator, is it going to cause you any bottleneck issues or do you actually have capacity on the C3-plus side and this will fit in nicely?

Yes. We have enough capacity for these particular customers. And we continue to look at additional de-bottleneck ideas both for Redwater I and Redwater II on the back end, so on the C3-plus part of those facilities.

Okay. So just to be clear, though, the C3-plus coming in, does it cause you problems in boxing out C2-plus mix?

No. In the overall mix, it's not material so we just push it in with everything else.

Okay. Just the last question, maybe coming back to Empress, I know you've not wanted to comment on specific extraction premiums, I'm just wondering if you can give any commentary on the direction of what happened or the conversations in light of the mainline decision and the impact it's had on volumes and where gas is going into storage right now?

Well, generally, in terms of what's happening at Empress, I mentioned earlier, our volumes are being maintained. We see the quality of gas at Empress slowly improving. It is slowly getting richer. And we see propane prices being robust both in Edmonton and in Sarnia. So we're pretty well-positioned there for, it looks like the balance of this year. We can't predict the weather but if we have a normal winter, we should have a strong third and fourth quarter.

Any early indications of the negotiations going into the 2014 gas year?

I don't have that knowledge.

Not at this stage, Robert.

Okay. Great. Thank you.

Robert Catellier, Macquarie.

Up a little bit on the Empress question. A little surprised to hear the comment about the gas stream richening. On one the one hand, obviously, producers are targeting liquids rich gas but at the same time there's more infield processing and deep cut capability. So I wondered if you could address that and then my second question has to do specifically with the extraction premiums. If you have a comment there, given the AECO basis widening a little bit here in cash market given the new TransCanada tolls?

I'll talk about the gas. The only gas, as you know, being drilled is rich. And we have anything that's dry gas on heavy decline, anything that's sour gas on heavy decline. And that's all being backfilled by rich gas. And so notwithstanding there are some deep cut facilities being built, every facility out there, depending on where it's located, is choking on liquids right now. So I'm not going to try to predict the future but if -- you can predict it yourself, if you only gas being drilled is rich, that's going to be what we expect to happen in the future.

Yes, in terms of extraction premiums, Rob, we really can't talk about them, but I don't think there's been a material change in the extraction premiums at Empress this year compared to last year. There's really has not change notwithstanding the fact that pricing has improved somewhat this year. So our profitability at Empress, as Mick has mentioned, it looked pretty solid for the third and fourth quarter of this year and possibly the first quarter of next year assuming, again, that we have a normal winter. Because inventories are really -- are quite low and we had strong pricing in the first and second quarters of this year relative even to Mont Belvieu. So, we were trading at premiums that at Sarnia that were much higher than what we had experienced certainly a year ago.

And then just add to that, we see pretty soft gas prices at AECO as well.

Right. So from those comments then, it appears to me that the actual change here is structural in as much as the composition of gas has just changed so much that it's been a bit of a step change in the profitability there. Less so than the effect of the extraction premiums maybe ticking down a little bit from previous quarters?

Tell you what though, it would be more related to actually the pricing for the product. The inputs are -- they're going to change, they're going to vary but I don't think there's material change in the inputs, in a sense. It's just the pricing at Sarnia has improved because there has been -- you guys had -- you people in Eastern Canada suffered a pretty cold winter and that was actually good for us in Western Canada because we could ship our propane out to the east and actually do fairly well. But we could see it too, our inventories for propane in Eastern Canada are at five-year lows compared to last year when they were at five-year highs. So, that's the fundamental change that's occurred here is more to do with the pricing of the product as opposed to the inputs.

Yes. The product is slowly getting richer. I don't want to overstate that. It's, as Bob says, much more -- volumes are flat. It's slowly getting richer but it's really a pricing story.

Yes.

Okay. And then finally, your comments on LPG terminal bring up the question of citing risk. On the other hand, you do have some assets and pipeline access to Sarnia and some tools there you might be able to use. I'm sure you've thought through this possibility, but how would the economics or the opportunity compare to having maybe a central Canada export terminal versus one on the west coast? Would the -- do the economics work there? We have assets they are already, but the product really trades at a premium in Sarnia versus a citing risk on the west coast.

Well, Rob, we don't really -- we don't see the citing risk on the west coast as being really much of an issue. What we're learning as we go through this whole process is that accessing international propane prices might be possible on the west coast, which is significantly different than pricing at Sarnia, Mont Belvieu, or at Edmonton. And that's what this might be all about. And if we can find a way to get access to a higher price for propane out of Western Canada, that benefits our customers big time and we're happy to transport it, frac it, terminal it, and have it get on to ships. So, I still think that that's where our mind is focused. We've made good progress in the last six months with respect to getting access to a decent export terminal and now it's a matter of lining up customers for the product. And I can tell you that there are a lot of people that are interested in that concept.

Okay. Thank you.

Steven Paget, FirstEnergy.

If the fractionators in the Edmonton region are full, could you please comment on where the 13,500 barrels a day of new volumes from Saturn I might go when it's commissioned?

Those are -- I can't comment on where they are going, but I'm aware they have a home.

Are there other volumes that might not have a home?

I can't answer that. I don't know.

Steve, it's fair to say that some of the producers are lacking in fractionation capacity. As Mick has said, the fracs seem to be full so they're trying to find a home and we're trying to accommodate them the best we can but in some cases people are having to shut in production because they don't have a home for the liquids.

So is there a possibility of short-term moving up the liquids unfractionated? Say, by rail?

That's not anything that we're really looking at, Steve, and so no, not something that we're looking at. Others might.

Okay. Thank you. Another midstream company has commented that NGL pricing at Edmonton is becoming less reliable. So could you comment on whether you agree with this and whether this is a positive for Pembina and what the opportunity might be?

Well, if you look at last year's prices compared to this year's prices, I'd agree that they don't look very reliable. But in our current budget year, we're pleased with inventory levels as we look out. As Bob mentioned, we do believe the industry needs a solution. If all the gas -- liquids rich gas that's being proposed to be drilled gets drilled, we'll need additional markets, whether they're in the US, in Eastern Canada or export. So something's got to happen in the next two to four years as an outlet. Same as natural gas and oil. It's the same story.

Could Pembina provide some NGL pricing benchmark? Or is that not in the scope of your Business?

It really isn't in the scope of our Business even. To the extent that -- we're taking the position that for the most part if a customer wants to market their own NGLs, we're happy to give them the barrels back after we've fracked them but the market is going to be the market. We're not making a market for product. Nor do we intend to. So as Mick has said, to the extent that we can access other markets, other than the traditional markets, then that will be a positive for our customers. To the extent that they get paid more money for the product, it will encourage more resource development and we're happy to be involved in the value chain, but we're not looking at getting involved in taking on the commodity exposure. But there's a commodity opportunity here. As long as we provide the facility.

Excellent. Thank you. Those are my questions.

Linda Ezergailis, TD Securities.

Maybe this is a follow-up to Steven's question. Not just in terms of the physical barrels but can you give us an update on how you're thinking about your overall hedging strategy whether it be physical or financial, and a sense of in aggregate, how you're frac barrels are -- what percentage is hedged out through the next little while?

I'll let Peter answer that question, Linda.

We previously announced that our hedging policy on the frac side is to hedge a base minimum level of 50% of the gas supply cost. Right now, we're in the low 50%s, around about 53% to 55% of our gas supply costs hedged. We're hedged around about the CAD35 type range today. The spot market is up at CAD40, CAD41. We see the potential for that with lower gas prices going a little bit higher going into the fall. So we're happy staying where we are right now. And in reality, the frac component of our business is getting lower and lower as the commodity prices are increasing and the rest of our business increases as well. So we're not all that concerned about the level of frac exposure that we currently have.

Okay. And just as a follow-up question with respect to Musreau II, what are the expected returns -- typical? Or is there the base returns might be higher given the environment? Or would the higher returns be coming from handling the product throughout your system?

I'd have to say they're typical returns that we'd expect from a facility like Musreau.

Great. Thank you.

(Operator Instructions)

David Noseworthy, CIBC.

Just a couple of follow-ups. With respect to the Cornerstone Pipeline, when does Pembina anticipate completing the work under the ESA?

We'll be very well underway by March of 2014.

And will that -- and is the expectation or at least Pembina's expectation that your potential partners there, KOSP, will make their FID in the same time period?

Yes. And that also coincides when we think we'll be out of money. (laughter)

All right. It all comes together.

That sounds surprising. (laughter)

And then in staying with Cornerstone here, with regards to being a 50% shipper on the diluent line, is this a long-term plan or would Pembina contract the capacity as firm long-term demand materializes?

It's -- our base plan is -- and we're out in market right now seeking customers for that capacity -- that we would offer product up in that area on a commercial basis. So rather than inviting shippers to have firm contracts on our capacity, we would maintain that and offer the product at delivery point. That's certainly not to stop another customer from giving us a call and taking out firm service in addition to our plan. Certainly there are other large customers and that system is readily expandable. And so were there other material customers to show up between now and 2014, I think we could accommodate them.

And when you look at condensate pricing, say, in the Athabasca Oil Sands versus Edmonton, is there a significant differential there?

It depends on where you are. But if you're in an area where there is no pipeline service, yes, there is. If you're in an area that's well serviced by pipelines that have capacity, which actually are few, then perhaps the differential is only the transportation cost. But in the particular area we are looking at, is not currently well-served by pipeline.

And then just a quick question on your crude oil rail terminal that's starting up in September. Does that facility displace capacity that you're using for other things today? Or is it incremental and therefore the returns would be incremental?

Right -- the initial foray there is at RFS, so it's using idle capacity. When RFS II ramps up, then there's a chance that capacity will go back into NGL service. But we'll have to see what else is going on in the market at that time.

Okay. All right. So potential expansion possible on your rail there for -- I don't know how you would -- for one thing or another?

I wouldn't necessarily say there. My former comment might not mean additional, might just mean redeployed into propane but certainly, rail opportunities exist elsewhere on our asset base.

Understood. Okay, that makes sense. And then one last question on your crude oil marketing, and just wondering if you could help us understand the comment made in your MD&A about narrow price differentials resulted in fewer storage opportunities and lower margins and you're comparing Q2 2013 to Q2 2012. When I look at the heavy-light differential year-over-year, it actually got wider, so what differentials would impact Pembina's crude oil marketing business beyond the heavy-light?

Really, all the differentials. We provide diluent services for customers, we provide service storages. So, whenever we have an outage, we can buy barrels -- not we, but if there's a downstream outage, we can for example buy barrels as favorable price, store them and when the outage resolves itself, we can remarket them. We don't do that -- we don't take the risk on that activity, but we buy and forward sell, taking advantage of our storage position and so we're really looking for imperfections between all commodities.

So there's just fewer--

Not all but all the commodities we touch.

Right. So it's just to say there were fewer anomalies this quarter than last quarter?

Yes.

That's a nice way to put it, David.

If Bob Jones were here, he'd be talking about options (laughter) and that would get very confusing.

Yes. We'd be on the phone for a while. (laughter)

Yes, anyway, we're trying to actually reduce the variability in all of our businesses. And, as Mick mentioned, if we increase the number of options that we've got, it gives us more opportunities to take advantage of the imperfections in the marketplace.

Appreciate it. Well, hank you very much. Those are my questions.

I turn the conference back over to our presenters.

All right. Well, thanks for those who participated in the call today, and obviously we're pretty enthused about all the prospects here at Pembina. And happy to be able to deliver on our promises, in a sense, because we have given the market indication that we are going -- we expect to be increasing our cash flow per share and our dividends per share and we're on plan. So we'll have more to say in the third and fourth quarter of the year. Thank you.

This concludes today's conference call. You may now disconnect.