Pembina Pipeline Corporation (PBA) Q3 2013 Earnings Report, Transcript and Summary

Good morning. My name is Denise, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Pembina Pipeline Corporation 2013 Third Quarter Results Conference Call. [Operator Instructions] Mr. Bob Michaleski, you may begin your conference.

Thank you, Denise. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our third quarter 2013 results. I'm Bob Michaleski, Pembina's Chief Executive Officer. And joining me on the call today are Mick Dilger, President and Chief Operating Officer; Peter Robertson, Vice President of Finance and Chief Financial Officer; and Scott Burrows, Vice President of Capital Markets. For this morning's agenda, we will follow our standard process. I'll spend a few minutes reviewing our third 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 the comments made today may be forward-looking in nature and they're 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. So both our financial and operating performance during the third quarter and first 9 months of 2013 were very strong. I'm happy to report that Pembina delivered another successful quarter and continued driving value for our shareholders. With the announcement of a new growth project, our recent dividend increase and growing and sustainable cash flows, Pembina remains committed to maximizing long-term and sustainable shareholder returns. At a high level, our current -- or sorry, our strong financial and operational performance was positively impacted by several factors. These include higher propane prices, which benefited our Midstream business, and increased volumes on our conventional and oil sands pipelines, as well as in Gas Services due to higher customer activity in our operating areas. Pembina and its shareholders continue to benefit from our integrated service offering, our continued investment in our businesses and the strategic location of our assets. In the third quarter, adjusted EBITDA increased by 31% to $201 million from $154 million in the third quarter of last year. This increase was largely because of improved operating results in each of our businesses and returns on new assets and services. When looking at the year-to-date figures, adjusted EBITDA totaled $596 million compared to $391 million in the same period of 2012 due to the same reasons I just mentioned and the completion of our Provident acquisition, which occurred in April of 2012. Adjusted cash flow from operating activities increased almost 42% to $189 million during the third quarter of 2013 relative to the same period last year when adjusted cash flow from operating activities was $133 million. Per share, this increase was approximately 33%. Year-to-date, the jump in adjusted cash flow from operating activities is even more impressive. We saw an increase of 68% from $322 million in the first 9 months of 2012 to $540 million for the same period last year -- this year, sorry. Per share, this increase was just over 36%. Our strong financial results for the periods were the result of very solid operational performances across each of our businesses. For our conventional pipeline business, average throughput increased by 10% during the quarter and by 9% in the first 9 months of the year compared to the same periods of last year. Increased oil and gas producer activity in our service areas resulted in a number of newly connected facilities and increased volumes at our existing connections and truck terminals. Conventional Pipelines saw its revenue increase by 31% during the third quarter of 2013 to $103 million compared to $79 million in the same period last year. For the first 9 months of the year, revenue increased 25% to $300 million from $240 million for the same period of 2012. These increases were primarily due to stronger volumes, as I've mentioned, and new connections, as well as the pipeline segment we reassigned from Midstream at the beginning of the year. Offsetting higher revenue in Conventional Pipelines was OpEx, which increased around 25% for both the third quarter and first 9 months of the year compared to the same periods last year. These increases were largely because of our ongoing pipeline integrity program, as well as the additional expenses we experienced for power and labor. Third quarter operating margin was 34% higher this year than in the same period last year and approximately 27% higher for the first 9 months of the year compared to the first 9 months of 2012. Our Oil Sands & Heavy Oil business generated improved results for the periods as well. This was largely because we transported volumes beyond our contracted capacity on the Nipisi pipeline as a result of a new pump station that we placed in service on this system. As such, our operating margin for the third quarter and first 9 months of 2013 increased about 13% and 11% compared to the same periods of last year. Gas Services also saw a higher throughput, with the Cutbank Complex processing an average of 288 million cubic feet per day during the third quarter and 293 cubic feet per day in the first 9 months of 2013 compared to 275 million cubic feet per day in both the third quarter and first 9 months of 2012. These increases reflect sustained interest of producers and, more specifically, our customers in the areas surrounding our Gas Service 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 the Cutbank Complex and greater recovery of operating expenses bumped revenue in this business by 33% and 35% for the third quarter and first 9 months of the year. Offsetting this revenue increase were higher operating expenses, which were largely the result of power, operating labor and maintenance costs associated with higher volumes and increased activity at the expanded Cutbank Complex. Overall, operating margin in Gas Services increased about 25% and approximately 25 -- 27% for the third quarter and first 9 months of 2013 compared to the same periods last year. For Midstream, this is the second reporting period where we can draw a true comparison between a given period in 1 year to the next. As a reminder, the assets we acquired from Provident are reported in our Midstream business and we don't -- we didn't own these assets until April of last year. Our NGL Midstream activities had another solid quarter. Operating margin for the period increased 40% compared to the same quarter last year, and NGL sales volumes during the quarter were -- of 2013 were almost 99,000 barrels per day, a 14% increase compared to the third quarter of 2012. This increase was driven by higher sales of propane, butane and condensate. Our Redwater West assets, in particular, benefited from a stronger year-over-year propane market, bringing in an increase in operating margin during the third quarter of about 31%. Similarly, Empress East operating margin benefited from stronger year-over-year propane markets, as well as lower inventory acquisition costs driven by lower extraction premiums. Operating margin at Empress East again increased substantially by almost 63% to $19 million during the third quarter of this year compared to the same period of 2012. Moving to our crude oil-related Midstream activities. Operating margin increased about 6% during the third quarter of 2013 compared to the same period last year due to our ability to capitalize on differentials related to specific commodities during the quarter and increased activities and services at PNT and at Pembina's truck and full-service terminals. On a year-to-date basis, higher volumes and increased activity on Pembina's pipeline systems, robust demand for Midstream services, wider margins in the first quarter of the year, as well as increased throughput at the crude oil Midstream truck terminals, resulted in an increase in operating margin of about 14%. As I noted in our first quarter's conference call, some of the opportunities we were able to 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 and storage activities, and we have seen this business normalize a bit through the second and third quarters. On a consolidated basis, results of our businesses were very positive. The third quarter proved to be another successful period in which we were able to demonstrate our continued ability to improve our financial and operational results by capitalizing on our integrated service offering and extracting further value from our assets. I'll now provide a relatively brief update on our growth projects. Conventional, we have substantially completed, or are just about start commissioning, our Phase 1 NGL expansion, which will increase capacity in our Peace and Northern pipelines to 167,000 barrels per day. We are also continuing to progress with our Phase 2 expansion plans, which will further increase NGL capacity to 220,000 barrels per day by mid-2015. For our crude oil and condensate expansions, we have substantially completed and are just about to start commissioning our Phase 1 expansion, and we'll bring an additional 40,000 barrels per day of crude oil and condensate capacity on the Peace Pipeline, and we'll be accepting December volume nominations from our customers. We are continuing to progress detailed design and engineering work for our Phase 2 expansion and expect the regulatory process to go quite smoothly. Once Phase 2 is complete, our crude oil condensate capacity will reach 250,000 barrels per day by late 2014. In addition to all of this, in September, we announced plans to proceed with the $115 million Simonette pipeline expansion. This project was not part of our previously announced capital expenditure plans and was driven by area producer demand for firm service between Simonette and Fox Creek, Alberta. The Simonette pipeline expansion is expected to initially deliver 40,000 barrels per day of liquids to our Fox Creek Terminal and will access our previously announced Phase 1 and 2 Peace expansions. Once the project is complete, it is expected to provide us the operational flexibility for additional future volumes nominated through our previously announced Open Season process that would support a potential Phase 3 Peace Pipeline mainline expansion. The new pipeline is expected to be in service in the third quarter of 2014, subject to the necessary environmental and regulatory approvals. Once complete, we will have 3 pipelines in the quarter capable of segregating and shipping various grades of crude oil, condensate and natural gas liquids. We are also installing 8 clean crude oil and condensate truck unloading risers at our Fox Creek Terminal to help facilitate trucked-in volumes to access Edmonton area markets through our Peace Pipeline mainline expansions. We expect to have these risers in service before the end of this year. Lastly, on our Open Season, we are currently working diligently to finalize mining transportation agreements with our customers. The process is proceeding very well, and Pembina expects to have an update early in the new year. In our Oil Sands & Heavy Oil business, we completed an additional pump station on the Mitsue condensate pipeline, which brought Mitsue's capacity from 18,000 barrels per day to 22,000 barrels per day during the quarter. We also announced -- and also continue to move forward with the work related to our previously announced $35 million engineering support agreement for the proposed Cornerstone Pipeline System. I'll turn now to new developments in Gas Services. In late October, we completed and placed our Saturn I facility and associated pipelines and infrastructure into service. The Saturn I facility is a 200 million cubic feet per day deep cut processing plant and has the capacity to extract up to 13,500 barrels per day of NGL. The plant is currently seeing throughput of 165 million cubic feet per day with liquids recovery coming in ahead of expectations. I'm happy to say that we completed this project on budget. As announced back in August, we are proceeding with Musreau II, a new 100 million cubic feet per day shallow gas plant and associated NGL gas gathering pipelines located near our existing Musreau facility. The facility is expected to cost $110 million and is underpinned by long-term take-or-pay agreements. Musreau II is designed to handle propane-plus and is expected to yield about 4,200 barrels per day of NGL for transportation off our Conventional Pipelines. Regulatory and environmental approvals are now in place and construction is underway with the targeted in-service date in the first quarter of 2015. With respect to our other previously announced projects, construction on the fully contracted Resthaven gas plant is still on track to be in service by the third quarter of 2014. Lastly, we will -- we have received the regulatory -- required regulatory and environmental approvals for Saturn II, which is a 200 million cubic feet per day twin of Saturn I, and are progressing construction with an expected in-service date of late 2015. Saturn II will leverage engineering work completed for Saturn I and is expected to cost $170 million. We expect the Saturn II facility will have the capacity to extract approximately 13,500 barrels per day of NGL, which will be transported on the same liquids pipeline lateral Pembina constructed for the Saturn I facility. Now on to our Midstream business. We continue to see growth opportunities aimed -- increased opportunity for our customers in the Midstream space. Our largest project in this business is the second 73,000 barrel per day fractionator, RFS II, we're constructing at our Redwater site. During the quarter, we completed land clearing, began washing the feed cavern for the fractionator, ordered all long-lead equipment and are progressing construction. We expect RFS II to come in service in the fourth quarter of 2015. As mentioned last quarter, we are upsizing certain facilities associated with RFS II to accommodate the potential development of the third facility, RFS III. We haven't put commercial contracts in place yet, but we believe there is sufficient demand for fractionation capacity beyond what will be available after RFS II is complete. If RFS III does proceed, it would leverage engineering and design work for both RFS I and RFS II. During the third quarter, we also completed the land acquisition in the Alberta Industrial Heartland for approximately $20 million. The site, which we are calling the Heartland Hub, will be a further build-out of the larger Nexus Terminal and features existing real access and utility infrastructure to support the future development of rail, terminalling and storage facilities. Further to that announcement, we also entered into a multiyear agreement with a major North American refiner for loading up to 40,000 barrels per day of various crude grades on to crude oil rail cars at our Redwater facility. We are pleased to announce that late October, we loaded at Redwater, which we believe to be the first 100-plus car unit train in crude oil service to leave the Western Canadian Sedimentary Basin. This highlights the advantage of pipeline connected service integrated with storage and rail. This is part of a phased expansion of terminalling service and is a service Pembina will be building out at its Nexus Terminal. We are also actively working on the development of a propane export project as we see this as an opportunity that fits our integrated strategy and one which could help alleviate some of the propane oversupply we are seeing in Canada and North America. We are still looking at various options for the terminal and associated infrastructure, as we're finding that the more involved we get with this project, the more that we're learning about which sites are most economical and practical. I'm happy with the progress we're making and hope to be able to provide more details in the coming months. As always, ensuring we have the right amount of capital in place to fund our projects remains an important component in our plan to execute on our growth strategy. To that end, so far in 2013, we have successfully raised almost $950 million through various public financings. In July, we closed our first preferred share offering for gross proceeds of $250 million, followed by a second preferred share offering in October for gross proceeds of $150 million. Early in the year, we also issued $200 million in 30-year notes and raised $345 million in equity. At the end of the third quarter, Pembina also has over $1.5 billion of unutilized debt facilities available and exited October with $75 million of cash. Given our healthy balance sheet and successful financing programs to date, Pembina remains well positioned to accomplish our goals and continue to lever superior and improving results for our shareholders going forward. So before closing, I'd like to take a moment to acknowledge this will be my last quarterly call as Pembina's CEO. At September, I announced my plan to retire at the end of the year after 35 years of service with the company. My time with Pembina has been rewarding on a professional level, of course, but also, and more importantly, on a personal level. I've met many great friends here over the years and have had the opportunity to become more involved with our great community at Calgary through various initiatives, including my role with United Way. I'm looking forward to continuing my relationship with Pembina and my colleagues as a member of Pembina's Board of Directors following my retirement as CEO. Mick Dilger, President and Chief Operating Officer, will succeed me as CEO effective January 1, 2014. Mick has worked closely with me and the board for many years, and he was identified early on in his career with Pembina as a potential candidate for CEO. I know our company is in the best of hands as I transition the role of CEO over to Mick and pursue retirement. Mick has the expertise, the business skills and, most importantly, the vision to see Pembina into the future. In closing, looking back at what we have accomplished over the year, I am very pleased with how 2013 has progressed and can say with confidence that we're well on our way to finish the year off with record financial and operational results. As I prepare for my retirement at the end of the year and transition my duties as CEO to Mick Dilger, I believe very strongly in Pembina's future and know that we have the right people and strategy in place to continue driving long-term and sustainable shareholder value going forward. With that, we can start the Q&A. Denise, please go ahead and open up the line for questions.

[Operator Instructions] Your first question comes from Juan Plessis with Canaccord Genuity.

Congratulations to you, Bob, on your upcoming retirement and to Mick on the new role.

Thanks, Juan.

Thank you.

Your MD&A refers to volumes transported in excess of contracted amounts on the Oil Sands & Heavy Oil division, which I think is due to the extra pumping station on Nipisi. What were the volumes transported in excess of the contracted amount? And do you have capacity for incremental volumes on that line?

I'm not really sure. I'll turn that one over maybe to Scott. If you got any detail there, Scott?

Yes. Juan, I don't think we're prepared to disclose the volumes. I can tell you they were above and beyond the take-or-pay contracts, and there is sufficient -- there is some capacity on that line to transport more than what we saw in Q3.

Okay. Can you also talk about if that total on the excess volumes is higher than the initial total?

Yes, it is.

Okay. You've mentioned that if you move forward on the Cornerstone Pipeline project, it should be in service by mid-2017. Based on that time frame, when would you need to have that project sanctioned by KKD Oil Sands Partnership?

It's Mick. The current sanctioning by them and ourselves is March 2014.

March 2014?

Yes. I'm not saying that if it were to delay a quarter, that would delay our progress yet. The way to look at it is as long as we keep working, that on-stream date is achievable whether it's sanctioned in March 2014 or at a later date. The main thing is that we continue to work on it.

Your next question comes from Carl Kirst with BMO Capital.

Just it was nice to see Saturn I kind of come on so quick, so fast. Should we expect as all of the new plants come on, that the ramp-up time will be as quick for the rest?

Well, we've mentioned a number of times that we are trying to standardize on 200 million a day deep cut designs and 100 million a day shallow cut designs, with, of course, with some operating flexibility. I think it's fair to say that provided we work with the same contractors using the same design, and Redwater would be another example of that, that we should be always improving the way we construct and the reliability of our construction timelines. That's our theory. I think it's logical, but it'll remain to be seen whether we can execute that.

I think as far as the start-up, if that's where the question was going, Carl, I think we always expect you're not going to be at 200 million a day from day 1. It is going to start up over a period of time as we work through the operations and system itself. But I think what we've learned from Saturn I has been very positive and I think we'll be able to apply that again to Saturn II and Resthaven. So again, I think we're going to get better at each one of these things as we do more.

Great. No, excellent. And then just a couple of micro questions, if I could. I just wanted to make sure I understood what perhaps a good run rate may be for the depreciation in the Conventional Pipelines. There were some reassessment of a number of things. But just kind of so we have a good idea going forward, is what we've seen in the third quarter about the proper run rate?

I don't have the details there. Peter?

Yes, we don't have the details there. There are some other factors impacting the depreciation in the last couple of quarters. One is the revaluation of the asset retirement obligation, a result of the increasing discount rates, that we do see some liability. And where we have more ARO than we do net book value, then that has a tendency to reduce the depreciation on the income statement. So you're seeing that impacting the run rate of depreciation. We can perhaps get back to you to what that might look like going forward in the absence of any further adjustments relating to the ARO.

Your next question comes from Linda Ezergailis with TD Securities.

In terms of finalizing your Phase 3 pipeline expansion and potentially a fractionator, can you talk about what the sticking points might be with your potential customers and when you expect to maybe finalize that and what sort of scope to the extent that you can comment on that as well?

Yes, I think -- I don't know if there's already any sticking points, Linda. I think part of the issue that we're facing, I think that could be facing our producers, really, is that a lot of the drilling in the area that we're looking to provide services to are relatively new. The results are relatively new and then we're expecting longer-term commitments from them. So I think that's really the issue. It's early innings in some cases and so it may be a little more difficult for them to make a longer-term commitment. And similarly, they're wanting to consider what alternatives they have for fractionation. And again, because it's early innings, they probably don't have a good sense as to what they really require. Mick, I'll let you pitch in here.

Yes, I think that was well said. The Montney, which is a little further away, people have a little more experience with. And then the Duvernay formation, which is very topical these days, people have less experience with, and so they're trying to balance the need to get Montney and further away production on stream with trying to slip in 1 more year of drilling results on the Duvernay, and that's a tough balance for many companies, or in both, a tough balance to strike. So we, as you know, we've extended slightly the timeline for people to enter into binding agreements. But as Bob said, we are still optimistic that we'll have something concrete to say in -- early in the new year.

That's great, very helpful. And just maybe a more detailed question. One of the dilemmas with having such great process is your cash tax profile might start shifting a little bit. Can you give us an update on that front in terms of your cash tax profile?

Yes, we're expecting cash taxes for 2013 to be around -- and between, say, $20 million and $30 million. But that cash tax won't be payable until filing time in the middle of next year. For 2014, again, it depends how well we do, but the good news and the bad news in the tax fund is that the run rate could potentially be between $50 million and $60 million for 2014.

[Operator Instructions] Your next question comes from Robert Catellier with Macquarie.

My question is similar to what Linda was asking on Phase 3. In the absence of committing the Phase 3, the interim success the producers seem to be having with the drilling, particularly in the Duvernay, is generating a lot of liquids production. So I'm wondering what the alternatives are for that production and when do they really hit a choke point where they have no other choice but to really start to move ahead and commit to a long-term solution?

Well, we are -- we just announced, I think, that we're building a bunch of truck risers in the Fox Creek area. I think there are 8 there. And so that will provide quite a nice interim solution and bridge the gap over the next little while. But your guess is as good as ours as how fast that production ramps up. Certainly, the results seem to be economic enough to turn the play commercial, is what people are saying. So there's no question that Phase 3 is going to be required, not just for the Duvernay, but as I previously said, the Montney and some of the deep basin areas as well. So something's got to happen beyond Phase 2 is our view.

So what you're saying is that the play is commercial, it's just a question of the timing required to herd all the cats and get them to focus on one particular solution?

Yes. I'm not saying it's commercial. I think that's what producers are saying. But yes, the rest of your statement is the way we see it.

Okay. I'd just like to pursue the volume strength a little bit on the NGL side. It would appear to me that the price increase the industry has experienced and the production growth is at least partly responsible for the strong volumes in the quarter, particularly because Q3 is typically seasonally weak. I'm wondering if -- what impact you are seeing at Empress from the changing tolls on the TransCanada pipeline and whether that -- those volumes are down at all and if you're making them up in other parts of your system, particularly in storage, or if you're just finding more opportunities to rail product to market?

Well, we're a volume taker at Empress. Generally, we haven't seen anything noteworthy happening down there. It's bumping along, generally, with a modest decline at Empress. But I think what's noteworthy is our volumes. Our facilities are remaining at or near capacity. And in Sarnia, we're a price taker, and so what's driving prices out there is a decent demand and the ever-growing propane exports in the Gulf Coast. Locally, in terms of volumes, people are turning their gas production on or off in any given quarter, so the drilling results and the volume results were as a result of the decisions made some time ago. It's not something that people can react to on a quarter-by-quarter basis.

Okay. And if you can just maybe give a comment then on the -- some of the volume growth you've been seeing and the implications for storage. Does the current storage footprint, including what you have underway right now, accommodate all your current growth projects, and in this case, and excluding Phase 3? So do you have enough storage just with what you have and then Phase 3 would add to the storage requirements?

Yes, we have not heard of any storage constraints at these volume levels nor do we -- have we heard that there will be any through the balance of the year.

But Rob, as a part of our overall strategy, we do continue to look at storage opportunities going forward. I know we clearly have them in front of us, but we're not in a position yet to share those with you.

Your next question comes from Matthew Akman with Scotiabank.

On Cornerstone, what is the hinge on, I guess? The engineering studies are underway, so is the success or outcome of that, the sanctioning primarily just based on the cost study?

Our sanctioning depends on our anchor tenant sanctioning their larger project. We, as I said earlier, we're expecting that to happen in March of 2014. So if they're a go, it would appear that we're a go. But the costs are relatively well defined now. I mean, we're continuing to work on those. But the cost estimates, I don't remember what class they are, but they have been worked on for about 18 months already. So what we're really doing now is we're finalizing routing and we're out in the field consulting. And so the real push now is more on a regulatory front, I would suggest, than -- let me say it differently, we're not expecting any surprises on the capital cost of the project.

Does the Enbridge Norlite announcement have any bearing, do you think, on the potential green light for Cornerstone?

Well, I think the green light on Cornerstone, as I said, depends more on our anchor tenant's views of the economics of their project rather than -- I don't think they're looking over at that announcement in any way influencing their sanctioning or not. As you know, the cost of pipelines and tariffs of pipelines are almost immaterial compared to the capital costs of developing the resource behind the pipes. So it's a much larger question for Statoil than a pipeline question.

Okay. One more question on propane. You guys are realizing, obviously, strong pricing now, much improved year-over-year with Sarnia connection that the old Provident assets always had. How important in that context is it for Pembina to get a propane connection off the West Coast? Or is that starting to maybe diminish in importance for Pembina?

Well, as you know, Cochin's reversing, the Cochin pipeline that currently carries propane out of Alberta, and it's going to reverse. And so there'll be -- when that is complete, there'll be another, I think, approximately 30,000 barrels of propane in the Edmonton market. If you layer on our second fractionator, as well as the possibility of other additional fractionation capacity coming on our RFS III, it's our belief that somebody needs to clear the market out of Edmonton. We're ramping up with rail car delivery capability to satisfy what's going to come out of RFS II. But longer term, I think it'll be good for Alberta producers to have another outlet for their product, just keep the price moving upwards.

And your next question comes from Robert Kwan.

I guess just coming back to Phase 3 on the pipeline and you're mentioning that you're finalizing the binding commitments, do you sense you're in exclusive negotiations with these parties?

Well, it's hard to say. I think that we're definitely treating it as if there's -- competition is alive and well. That's, I think, the prudent thing to do. And so whether we are or we're not, we are moving forward as if there was plenty of competition.

Yes, I think, Robert, just to add to that. I mean, the fact that -- we believe we're in conversation with more than 60 producers. We are real. We've got a Phase 1, Phase 2 expansion underway. We've talked about the Simonette, the Fox Creek pipeline. We are definitely moving forward, and I think we would only move forward if we were confident that we were going to have something to actually fill space with.

And I guess, can you talk about what percentage or a majority or -- if that's the case, of those conversations you're having, that RFS III and capacity there is being tied into, and if there's any conversations about new gas plant capacity, particularly to serve the Duvernay?

Well, we do -- what we're being asked for by many of our customers is an integrated value chain service. And there's going to be a lot more gas plants required for these volumes to be delivered than probably Pembina can build. So I think it's a fair assumption that we'll be building as many gas plants as we possibly can. Nothing has been finalized in that regard, but we're optimistic we'll keep our gas business unit busy. With the pipeline versus the frac, I think people are -- have more urgency in getting their pipelines -- pipeline capacity nailed down, and then we'll get the boomerang effect of once they complete that, looking at fractionation. And the reason that's our sense is that there are more frac options available to customers than pipeline options, and so they're going to focus on what they perceive to be the scarce resource first. But again, I think there's going to be lots of demand for fractionation beyond RFS II resulting from the Open Season we're running.

Yes, particularly, Robert, if we can find a solution as well for propane, I think that will be very helpful for our producers today and for the future as well. So again, it gets back to what Mick mentioned. It's the integrated solution that people are looking for, but I think that we do have to take it one step at a time.

Okay. Just last question, just on Empress. Now that we're in November, just any commentary on what -- how the 2014 gas year has shaped up and directional commentary on extraction premiums.

I'll turn it to Scott.

Yes, our contracting effort at both Younger and Empress for the November 1 gas year have been very successful. Obviously, we can't disclose what those values are, but we can say that the contracting was successful, meeting or exceeding our targets on both volumes and term.

I guess maybe just -- I know you don't want to give the exact number. Can you maybe then just compare it to the 2013 gas year?

No.

We'd like to, but we can't.

Yes.

Yes, it's a sensitive issue for us, Robert.

And your next question comes from Steven Paget with FirstEnergy.

First, best wishes to you, Bob, as you enjoy many years of retirement, your time away from the likes of us. Congratulations to Mick and Scott on your new titles, and to everyone on bringing Saturn I in on budget. If liquids recovery at Saturn is ahead of expectations, does that mean the plant is full of liquids at this point? Is the gas richer than expected?

No. The plant design is just exceeding our expectations. Part of it is that it's not -- it's only 3/4 loaded right now. And so whenever you -- it's like loading your car. If you only have 2 passengers in it versus 5, it seems to have a little bit better acceleration. So it's able to run a bit colder and very efficiently. When we -- I think we'll have more to say about whether it can exceed design over the long term once we get it up to or over nameplate at 200. So hopefully, the people are working hard there to allow that to happen.

Excellent. Is Pembina playing a role in supporting Shell's recently sanctioned Carmon Creek asset with diluent delivery?

Well, we are -- we have -- let me just say this. We have, from time to time, delivered diluent to Shell, and so that is a relationship we enjoy up there. But we can't really talk about what might happen in the future there.

Excellent. Can you please comment on the type of crude you loaded on the unit train at Redwater? Was it heavy or light?

Synthetic. Did you hear that?

Yes, yes. Finally, with propane exports opening up at the Gulf Coast, is Pembina seeing more customer demand for shipping LPGs by rail to the region?

What Mr. Lockett told me is that he's getting calls earlier than normal for people to satisfy their demand from that region. And so it's not like last year where we were phoning them to see if they needed any propane. They're phoning us much earlier than normal, so that's kind of anecdotally what we could say in response to your question.

Your last question comes from David Noseworthy with CIBC.

And just my congratulations to you, Bob, on a fantastic career, and obviously, to Mick and Scott who have increased responsibilities.

Thank you.

Thank you.

All right. Most of my questions have been asked, but a couple of cleanup questions. In terms of Empress, with lower volumes and NGL margins higher, why, in your opinion, are we seeing extraction premiums falling?

Sorry, can you repeat the question?

Yes, absolutely. You mentioned that volumes were basically -- generally declining at Empress, and year-over-year, we've seen NGL margins higher. And so it mentioned on Page 19 that extraction premiums have fallen. I was just wondering why we're seeing that, in your opinion.

Well, David, I think that there's obviously been other producers in the news that haven't fared so well with Sarnia. Remember, we are able to access the Sarnia market whereas some others aren't. So some people in the past have not had the same success with Empress. So we believe there could be less competition for the gas. The other thing is, as we've mentioned in the previous quarters, we've been aggregating more volumes through our Cromer facility via truck. And so part of our strength in volumes is not only Empress extraction, it's also aggregating liquids in the field and going to our Cromer facility.

I guess that was the point that I didn't quite understand. I would have thought with lower volumes and higher margins on a year-over-year basis, competition would have been hotter and I was just trying to understand why it wasn't.

But only certain parties can access those higher margins, right? There's only a few parties that have access to...

The Sarnia margins?

Sarnia margins.

We can pick that up offline as well with Bob Lock.

Okay. I'd appreciate that. And maybe just on taking a moment to talk about a smaller part of your business. I was just wondering how your efforts to develop the emulsion treating and water disposal facilities -- you talked about putting a certain number of these facilities to kind of bring new volumes to your pipeline over time. How are those progressing?

In terms of identifying locations and disposal wells, I think we've met our expectations. We are, though, in the process of building up our engineering capability in the oil Midstream business. And that's proven to be a little more time consuming than we thought. And until we're really comfortable that we have all the right people to start building 2 or 3 of those a year, that we're opting to take a slower approach than we first hoped. And so we're continuing to partner with people where that makes sense, where they have that capability. But in terms of our proprietary locations, that has been a bit slower to develop. But our strategy hasn't changed, that we would love to bring on a couple terminals a year. With the geologic developments, the resource play developments, that market is growing dramatically. So we think there's enough out there for everyone to fill their boots.

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

Okay, well, thanks to all for wishing us well in our new blocks in life, if you like. Certainly, from my perspective, I do appreciate the relationships that we've developed over the years. I think you all are doing a great job in your coverage of Pembina. And I think the team here will continue to try to provide the same sort of level of support that you've received in the past. So thanks again and wish you all well in your own careers.

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