Pembina Pipeline Corporation (PBA) Q2 2013 Earnings Report, Transcript and Summary

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. [Operator Instructions] Rob 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 I'll 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. And both our financial and operating performance during the 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 results. I'm extremely proud to say that Pembina has successfully delivered on a promise to increase shareholder value to 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. The new monthly dividend rate will be $0.14 per share or $1.68 annualized. This 3.7% bump, which is effective as of August 25 record date, reflects our confidence in the company's solid fundamentals, growing in sustainable cash flows and fee-for-service focus growth plans. Our accomplishments once again, demonstrates 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 the conventional and oil sands pipelines, as well as 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 $185.1 million from $125.9 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 $395.3 million compared to $237.3 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 of 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 6 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 systems brought total Conventional Pipelines revenue in the second quarter to $101.5 million, almost 30% higher than revenue of $74 million in the same quarter of the previous year. On a year-to-date basis, revenue increased just shy of 30% from $160.6 million in the first half of 2012 to $197.3 million in the first half of 2013. Offsetting higher revenue 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 of 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 6 months of the year compared to 2012. Our Oil Sands & Heavy Oil business generated better results during the second quarter of 2013 and the second quarter of 2012. This was because of higher recoverable operating expense across the business systems and a throughput beyond our contract capacity being transferred 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 an 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 6 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 result of labor and power cost 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 15% and approximately 29% for the second quarter in 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 1 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 a 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 commodity-related 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 $2 million in 2012 to almost $16 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 a 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 include at the crude oil Midstream truck terminals, resulted an increase in operating margin of almost about 17%. As I noted on last quarter's conference call, some of the opportunities, we're able to take advantage of during the first quarter of the year and which drove a such strong first quarter results are not typical, especially with respect to margins and certain storage activities, and we've seen this business normalize a bit through the second quarter. On a consolidated basis, results 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 plant producer turnarounds, which typically affect production rates and softer propane markets due to the seasonal inventory build throughout the spring and early summer. I'll now provide -- move on to provide you with an update on our growth projects. During the first 6 months of 2013, Pembina has secured approximately $1.5 billion in capital projects, which will help provide long-term and sustainable returns to our investors once complete. It is significant to note that the cornerstone pipeline project in Pembina's open season are above and beyond this number. I'll go over each briefly and we could talk more about them during the Q&A, if you have specific questions. Starting first with our Oil Sands & Heavy Oil business. On June 27, 2013, Pembina announced that we executed a $35 million engineering support agreement with the KKD Oil Sands partnerships or KOSP, in which Statoil is a managing partner. This agreement is to progress our negotiations related to building the proposed cornerstone pipeline system. The new pipeline system, which service KOSP's enhanced oil recovery development and would transport diluent and blended bitumen between northeast 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 $850 million and could be in service by mid-2017 based on preliminary design work. Executing the ESA is great news for Pembina. It moves it 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're investing about $55 million at our Redwater site for a new storage cavern for NOVA and associated facilities and upsizing some of the infrastructures 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 3 underground hydrocarbon storage caverns and a new full-service terminal, 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's 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 are 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 existing Musreau facility. The facility is expected to cost $110 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 of service by early to mid-2015. With respect to our previously announced projects, construction of the fully contracted Saturn I and the 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'll note that we revised our capital spending estimate for Resthaven in our quarterly report. We are now expecting the project to cost approximately $240 million versus our previous estimate of $210 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, 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 1 NGL expansion. But of course, we still have Phase 2 to finish. The 2 expansions together will see our NGL capacity on the Peace/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 3 pump stations in service and expects to bring the remaining 2 online by October of this year, which would complete the Phase 1 expansions and add another 40,000 barrels per day of crude oil condensate capacity on the Peace Pipeline. The Phase 2 expansion is also in progress and we are now into detailed design and engineering. We expect the rig-through process to go quite smoothly on this project. Once Phase 2 is complete, our crude oil and condensate capacity will reach 250,000 barrels per day on late 2014. Now as announced in April, we have also concluded our nonbinding 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 3 successful financings, demonstrating our ability to access capital as the market recognizes future value in a 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 as 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 $250 million and issued $200 million in 30-year notes in April. We also raised $345 million in equity in March of this year. Now with only $105 million drawn on our $1.5 billion credit facility at the end of the second quarter, Pembina remains well positioned to continue to fund our growth plans moving 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 with our integrated service offering. This service offering, our ability to leverage 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 $2.7 billion in dividends or approximately $19.64 per share since its inception in 1967. With that, we can start the Q&A. So Tiffany, please go ahead and open the line for questions.

[Operator Instructions] Your first question comes from the line of Linda Ezergailis of TD Securities. Your next question comes from the line of David Noseworthy of CIBC.

So maybe I'll just start off with some of your growth project updates. In particular, can you tell us a bit more about the $65 million Resthaven scope design change? And how Pembina expects to recover on those capital cost? And perhaps, how those returns on the incremental capital compared to those anticipated on the original $175 million?

So David, I think the $65 million was with respect to a couple of projects. So 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 as just ensuring that we've got adequate pipe size available to handle the potential volumes from a third-party -- from a third fractionator, which I think is going to cost us somewhere around, I think $25 million to $30 million, roughly in that range. And so the other capital is related to other activity at Redwater. So in terms of anticipating how we're going to recover that cost will be associated with the commercial arrangements we make, ultimately when we get to build the third fractionator in Redwater.

And maybe -- there's one, I was wondering about was just Resthaven. I noticed the new capital cost was $240 million. And originally, it'd been $175 million, and so I was just looking at that, I guess, it also have to be a $65 million delta.

Yes. Sorry, David. Again, like I said, what I should explain is that the original engineering was done by one of our customers in -- for the Resthaven facility. And when we start getting into the details, it was obvious that things had changed. And so we actually had to almost reengineer the project and so that resulted in the increase in cost, as well as the fact that it looks like a lot of more of the volumes are going to come to that facility will have higher liquids associated with them, so that required -- again, a scope change. So we are in the process. I think 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's backstopping that plant?

I'm not sure if the commercial ranges are confidential, they're area producers...

And I think we should wait a little bit.

Yes.

All right.

Yes. That's fair, David, that the -- we've got, I think there's 4 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 filled gathering and processing over the next, say, 3 to 5 years?

Well, as a part of the -- what I'd rather call in our Phase 3 or echo 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 I'd say processing, that's processing in the field to handle liquids, and then pipeline transportation as well as fractionation. So I think from our perspective, we say that the potential is significant going forward over the next 3 to 5 years for future development of the gas processing facilities as well as pipeline and fractionation facilities.

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

It can range, and I'm going to say that like right now, we're moving say about 0.5 million barrels a day and but we can see that easily doubling by the end of the stage 3 expansion.

Right. 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 through that process, that we learned that there more likely be very high demand for propane being exported out of Prince Rupert. So I think that the -- are the approach that we're taking one now is to determine who is going to be interested and who's willing to commit. And that really is something that's important to us. Also, we were wanting to ensure that we have an adequate location for a facility, and I think we've made good progress there as well. So it's all been -- I think it's been pretty much, I think as expected under circumstances. And we're pretty optimistic that we're going to have a pretty good project here that we'll talk more about by the end of this year.

Your next question comes from the line of Juan Plessis with Canaccord Genuity.

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

If it's going to be a C3-plus facility, it'll 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'll depend on downstream markets, whether it's ethane extracted there or not.

Okay.

If there is ethane, it'll be 73,000. And if it's -- if there is not, it'll be 55,000. That's the plan anyway.

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, do we see any synergies? I think, it's already -- we're taking over operatorship, we've hired their staff and we will 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 I mean, there'll be capital synergies because we're using existing equipment.

Yes, okay. 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's an interim process in the sense. We've been in conversations with probably, I'm going to say, 25 to 30 producers to date, trying to assess their requirements. And at this stage, I think it's quite -- it's a little bit too early. I think my response to the question from David's, it's early to say it. We expect to have at least 0.5 million barrels a day of product to move on to that, but it could be more than that. And in terms of cost, you're talking way, which is $1 billion to $1.5 billion, that's just pipeline related. And there will be other facility additions that will be necessary is 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.

Your next question comes from the line of Carl Kirst with BMO Capital.

Just following up, perhaps on the Alberta -- the Northwest pipeline. One, should we be thinking of this as -- well, really in reverse order perhaps, as we look at spending more money to increase the fractionation for Redwater III, would that be something that would go hand-in-hand with something like the Northwest expansion? Or should we be keeping those -- the advancement of those 2 projects separate?

No. They should be looked at together, Carl, because that's really part of 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. Our customers, they understand that story, and they quite like it actually, that's their preference...

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

Yes. I think that's fair, Carl. Mick, I don't know if you have anything further to add.

No. That's all.

Okay. And then lastly, if I can just -- I understand it's early days, but given perhaps the early read to the nonbinding open season, is there a sense of timing on when something of this type of size come together? Is that sort of the reiteration, is that a 6-month process, is that a 12-month process, and understanding having it's own life and can move around? But just kind of as you sit here and look at it today, is there any kind of timing expectations?

Yes, I think Mick's got an answer.

The way I would think of it, we've announced Phase 1 and then a year later, Phase 2, and this is Phase 3a, I think 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 on different timing. And so we'll probably keep announcing expansions over the next number of years rather than a single block of volumes.

Yes. I think that, Carl, what we're hoping to be able to accomplish, the conversations are taking place now, but I think as Mick has said that it looks like there could be different levels of expansions. But we're 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. But as you can obviously tell, Pembina's feeling pretty confident of where we are in this project right now with a front-ending of the RFS III and accelerating some of the work on regulators and so on for the pipeline.

Great. 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 broader range of customers potentially?

Well, I think it's fair to say, Carl, we're moving to a broader range of customers. That is a customer we have been working and would like to still be a candidate, but not for the same commercial arrangement that we were thinking about initially.

Your next question comes from the line of Matthew Akman with 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, I think, Matthew, when you're making money, that's a good thing, obviously. 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. And in terms of other activity, in terms of rationalization of ownership and so on, I think conversations still are taking place, Matthew. But I don't think there's been a lot that's transparent here. I think we're continuing to try and source the product we require at Empress and still have generate profitable 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 in Empress are 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 the year where I think you guys are probably spending more than you have before, sometimes there's millions on it and it's also critical in light of the focus on safety and environment and also the expansions you're 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?

I think 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 have been many surprises. I mean, these are things that we're just doing. We're increasing the testing. We're running the higher pressures, so we have to ensure that the pipelines are going to be certified to round up those higher pressures. And I think 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 kind of business as usual for us, but it does mean that we do have to continue to front-end these expenditures in advance so our new volume is coming to the system.

Your next question comes from the line of Robert Kwan with 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? And is this the time of year where you'll be looking at something else, either with Q4 or Q1 results?

Well, Robert, I think that -- in response to your first part of your question, I think the executives here in this room are pretty confident with respect to what the future looks like for Pembina and particularly in light of all the projects we're working on to date, and in some cases projects that we continue to work on. So clearly, that's the case. I think that with the guidance we've provided, Robert, in the past is, 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 until the third quarter of the year, the time we're working on our budget and so on. But I think we also do projections. We do 5-year projections based on projects we have in front of us. And 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, and I think that we're pretty feeling pretty comfortable with that. Will it come in 1 or 2 tranches? We haven't decided yet. So -- but I think it's -- right now, we're saying the guidance we provided, 3% to 5% per share per year is pretty doable. And I think it's something that the market hopefully will get to expect, which is similar to what we've done in the past. We look at our historical dividend ratios. They've been in 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. So just coming back to Musreau II, I know you don't want to get into any specifics with respect to your customers, but I'm just wondering as a group of those 4, 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?

I think 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.

Okay. And just with it being a C3+ mix versus your C2+ fractionator, is it going to cause you any bottleneck issues? Or do you actually have capacity in the C3+ side and that will fit in nicely?

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

Okay. So just to be clear though, the C3+ is coming in, did it cause you problems in boxing out C2+ mix?

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

Okay. Just on 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's 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 -- and propane prices being robust both in Edmonton and in Sarnia. So I think we're pretty well-positioned there for, it looks like the balance of this year, I mean 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 here?

I don't have that knowledge.

No, not at this stage, Robert.

Our next question comes from the line of Robert Catellier with Macquarie.

Up a little bit on the Empress question, a little surprised to hear the comment about how the gas stream richening. On the one hand, obviously, producers are targeting liquids-rich gas, but at the same time, there's more in-field 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 eco basis widening a little bit here on the cash market, given the new TransCanada tools.

Well, I'll talk about the gas. I mean the only gas being drilled is rich, and we have anything that's dry gas on heavy decline ending at 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, I guess, is choking on liquids right now. So we -- I'm not going to try to predict the future, but if you can predict it yourself, if the only gas being drilled is rich, I think that's going to be what we expect to happen in the future.

And really 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 been much change obviously and the fact that pricing has improved somewhat this year. So I think our profitability at Empress, as Mick has mentioned, that looks pretty solid for the third and fourth quarter of this year and probably the first quarter of next year assuming again that we have a normal winter because inventories are really quite low when we had strong pricing in the first and second quarters of this year relative to even to Mont Belvieu. So we're trading at the premiums at Sarnia that were much higher than that we had experienced certainly a year ago.

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

Right. So from those comments, and it appears to me that the actual change here is structural and 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?

I think it will be more related to the actual pricing for the product. The inputs are going to be -- they're going to change, they're going to vary, but I don't think there's material change in the inputs in the sense. But just the pricing at Sarnia has improved because there's been a -- you guys have -- people in the eastern Canada suffered a pretty cold winter. And that was actually good for us in western Canada because we could ship our propane to the east and actually do fairly well. But we can see it too, our inventories for propane in eastern Canada are at 5-year lows compared to last year when they were at 5-year highs. So I think that's the fundamental change that's occurred here. It's 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, as Bob says, much more. If volumes are flat, it's slowly getting richer, but it's really a pricing story.

Okay. And then finally, your comments on the LPG terminal and the -- bring up the question, I guess of siting risk, on the other hand, you do have some assets in the pipeline access to Sarnia and some tools there you might be able to use. I'm sure you've thought through this possibility. But would the economics or the opportunity compared to have maybe a central Canada export terminal versus one on the West Coast? Would that -- do the economics work there? Do you have assets there already, but the product really trades at a premium in Sarnia versus the siting risk on the West Coast?

Well, you know what, Rob, we don't really -- we don't see the siting risk on the West Coast as being really much of an issue. I think 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 I think that's what this might be all about. And if we can find a way to get access to a higher price per propane out of western Canada, I think that benefits our customers big time. And we're happy to transport it, to frac it, terminal it and have it get on to ships. So I still think that's where our mind is focused. I think we've made good progress in the last 6 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 we -- I can tell you that there are a lot of people that are interested in that concept.

Your next question comes from the line of Steven Paget with FirstEnergy.

The fractionators in the Edmonton region are full. Can you please comment on the 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're 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.

I think, Steven, it's fair to say that some of the producers are lacking in fractionation capacity. I think as Mick has said, the frac seems 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, I think the 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, Steven. So no, it's not something we're looking at. Others might.

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, I mean, 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, I think we're pleased with inventory levels. As we look out, I think, as Bob mentioned, we do believe the industry needs a solution if all the gas, the liquids-rich gas that are being proposed to be drilled gets drilled will need additional markets, whether there in the U.S., in eastern Canada or exports. So some things going to happen, I think in the next 2 to 4 years to -- as an outlet. The same as natural gas and oil. It's the same story.

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

It really isn't in the scope of our business, Steven. To the extent that -- we're taking a position that for the most part, if the customer wants to market their own NGLs, we're happy to give them their barrels back after we frac them. But if 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 I think that'll 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 I think as long as we provide the facility.

Your next question comes from the line of Linda Ezergailis from 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? I guess, whether it be physical or financial and a sense of in aggregate how your frac barrels are, what percentage is hedged out through the next little while?

I'll let Peter answer that question.

We've previously announced that our hedging policy on the frac side is to hedge a base mineral level of the 50% of the gas supply cost. Right now, we're in the low 50s, roundabout 53% to 55% of our gas supply cost hedged. We're hedged around about the $35 type range. Today, the spot market is up at $40, $41. 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. In reality, the frac component of our business is getting lower and lower as 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 kind of typical? Or is 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 say they're typical returns that we'd expect from a facility like Musreau.

[Operator Instructions] Your question comes from the line of David Noseworthy with 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.

Okay, 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.

All right. It all comes together.

That sounds surprising.

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

Yes, I think our base plan is in road in the 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 the delivery point. But 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 in 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's 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's only the transportation cost. But in a particular area we're 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. And 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.

So potential expansion possible on your rail there 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 in our asset base.

Understood, I'm still okay, that makes sense. And then one last question your crude oil marketing. I'm just wondering if you can 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. And 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 heavy light?

Really, all the differentials. I mean, we provide diluent services for customers. We provide storage services. 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 at a variable price for them. And when the outage resolves itself, we can remarket them. And 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. 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 the best way to put it, David. If Bob Jones were here, he'd will be talking about options, then that will get very confusing.

Yes, but we'd be on the phone for a while. Anyway, we're trying to actually reduce the variability in all of our businesses. And I think 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.

I'll turn the conference back over to our presenters.

All right. Well, thanks for those who have 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 I think we have given the market indication that we are going to -- we expect we're 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.