Pembina Pipeline Corporation (PBA) Q4 2012 Earnings Report, Transcript and Summary

Good morning. My name is Rob, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation Fourth Quarter Results Conference Call. [Operator Instructions] Thank you. I will now turn the call over to your CEO, Mr. Bob Michaleski. You may begin your conference.

Thank you, Rob. Good morning, ladies and gentlemen, and welcome to Pembina's fourth quarter conference call and webcast to review our 2012 fourth quarter and annual results. I am Bob Michaleski, Pembina's Chief Executive Officer. With me this morning are Peter Robertson, Pembina's Vice President of Finance and Chief Financial Officer; and Scott Burrows, our Senior Manager of Corporate Development and Planning. This call and webcast will follow our standard practice. I'll review the financial and operating results we released last Friday, provide an overview of our recent developments and then open up the line for questions. Before we begin, I'd like to point out that some of these comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, projections, risk and assumptions. I must also point out that some of the information I provide refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see Pembina's various public disclosure documents available at pembina.com and on SEDAR and EDGAR. Actual results could differ materially from the forward-looking statements we make or we may express or imply today. Now the fourth of 2012 brought record performance for Pembina's business and operationally, is one of our strongest ever. Quarter-over-quarter, we saw a 170% increase in revenue, a 100% jump in operating margin and 120% -- 126% gain in adjusted EBITDA. On a per share basis, we saw a 51% increase in adjusted cash flow from operating activities and a 4% increase in earnings. These and our annual results were driven by strong performance in Pembina's legacy businesses, as well as the addition of the assets acquired from Provident in April of 2012. On a full-year basis, we saw revenue, EBITDA and adjusted cash flow from operating activities come in significantly higher than in 2011. Our Midstream business is where we saw the most substantial increase, both on a quarterly, as well as an annual basis. During the fourth quarter, we saw a 411% increase in operating margin compared to the same quarter of last year. For the full year, Midstream's operating margin was $288.5 million, up 210% from last year's operating margin of $93.2 million. We integrated the Provident assets into this business, which accounted for the majority of the increase, but we also saw improved results from our legacy assets due to higher volumes and increased activity on our major pipeline systems. Our Oil Sands & Heavy Oil businesses also realized higher results, which can be attributed to a full year of operations from our Nipisi and Mitsue Pipelines and higher flow-through operating expenses. During the fourth quarter, operating margin increased 8% compared to the fourth quarter of 2011. And year-over-year, operating margin increased by just over 28% from $91 million in 2011 to $117 million in 2012. Turning to our Gas Services business. During 2012, we processed higher volumes at the Cutbank Complex, and also through our Musreau Deep Cut, generating $14.4 million in operating margin during the fourth quarter, which represents an increase of 11% over the same period last year. For the full year, this business operating margin was also about 20% higher than in 2011. In our Conventional business, the quarterly and full-year results were strong. Throughput was nearly 14% higher in the fourth quarter of 2012 and the fourth quarter of 2011, and our full year operating margin was about 15% higher than in 2011 as a result of a 10% year-over-year increase in average throughput. Pembina incurred G&A, including corporate depreciation and amortization, of $27.3 million during the fourth quarter of 2012 compared to $21 million during the fourth quarter of 2011; and $97.5 million for the full year compared to $62.2 million for the same period of 2011. The increase in G&A is mainly due to the addition of employees who joined Pembina through the acquisition, an increase in salaries and benefits for existing and new employees and increased rent for expanded office space. Now many of you have heard about Pembina's growth story and the projects we have on the books for 2013, so I'll go over them briefly, and we can talk more about them during the Q&A if you have specific questions. In the Conventional Pipelines, looking at the growth process, as you likely know, we recently announced having secured contracts to proceed with our Phase 2 crude oil and condensate expansion on the Peace Pipeline. Because we broke our capacity increases to our Conventional Pipelines into a number of phases, it may appear a bit complicated. At a high level, the easiest way to explain it is that we are bringing on incremental capacity in each phase as new pump stations are brought into service. We have split the expansion into 2 distinct phases: Phase 1 and 2, each of which has a crude oil and condensate and natural gas liquids component. The Phase 1 crude oil condensate expansion is estimated to cost $30 million and will add 40,000 barrels a day of capacity on our Peace Pipeline by October of this year. With Phase 2, which we expect to cost $250 million, including the mainline expansion and tie-ins, we will increase the Peace Pipeline capacity by an additional 55,000 barrels per day, bringing total capacity on the system to 250,000 barrels per day. Given the intensive capital investment required for the second phase, we have already secured a number of contracts with customers to underpin the project. So subject to regulatory and environmental approvals, we anticipate being able to bring the Phase 2 expansion into service by late 2014. A combination of Phase 1 and Phase 2 expansions will increase capacity by 61% from current levels. Turning now to our NGL capacity expansion on our Peace and Northern Pipelines or collectively, the Northern NGL System, we completed a recontracting initiative in 2012 on existing and new volumes to underpin the Phase 1 expansion. We expect this first phase will cost approximately $100 million and add roughly 52,000 barrels per day of NGL capacity to the Northern NGL System by October of 2013. We have also initiated a proposed second phase expansion to the Northern NGL System and are actively working to accelerate the timing of this project because of the volume of NGLs we are seeing coming online by producers. While we're still working to secure customer commitments, the Phase 2 expansion will increase capacity from 167,000 barrels per day to 220,000 barrels per day and estimated to cost approximately $450 million, including tie-ins. Now subject to reaching contractual arrangements as well as regulatory environmental approval, the second phase NGL expansion could be complete in early to mid-2015. The Conventional Pipeline is also constructing the pipeline components of our Saturn and Resthaven gas plant projects. These 2 pipeline projects will gather NGL from the gas plant -- from the gas plants for delivery to Pembina's Peace Pipeline system. We have reached the required environmental -- sorry, we have received the required environmental and regulatory approvals, we've awarded construction contracts and have begun construction on both projects. In Gas Services, we're working to bring our total processing capacity to 903 million cubic feet per day, net to Pembina. This includes enhanced NGL extraction capacity of approximately 535 million cubic feet per day, of which 205 million cubic feet per day is currently in service. During the year, Pembina completed a deep cut and a shallow cut expansion of the Musreau facility, which is located at the Cutbank Complex. With these 2 expansions now complete, we have an aggregate raw shallow gas processing capacity of 425 million cubic feet per day, of which, 368 million cubic feet per day is net to Pembina, as well as enhanced NGL extraction capacity of 205 million cubic feet per day. Gas Services is also making steady progress on the construction of our fully contracted Saturn and Resthaven gas plants. We expect the Saturn facility and associated pipelines to be in service in the fourth quarter of 2013 and the Resthaven facility and associated pipelines to be in service in the third quarter of 2014. Construction on both facilities is well underway, with over 95% of the major equipment ordered and on-site at the Saturn facility and over 80% of the major equipment ordered for the Resthaven facility. As I'm sure you can appreciate with the acquisition, Pembina's Midstream asset base has grown substantially. Our future growth prospects related to this business now span across the crude oil and NGL value chains. In 2013, the capital we are spending in the Midstream business is primarily directed as fee-for-service projects that are expected to continue to increase this business' ability and predictability. We are continuing to advance our full-service terminal program which we announced last year, and we will be putting 2 new facilities into service in 2013. This includes a joint venture project in the Judy Creek area of Alberta that will serve the production coming from the Beaverhill Lake and Swan Hills and a second full-service terminal that serves producers in Cynthia and west of Drayton Valley -- Cynthia area, west of Drayton Valley. Work also continues on the Pembina's Nexus Terminal or PNT, as we like to call it. There, we'll be adding a truck terminal, constructing storage facilities which are expected to come onstream in 2015 and commissioning the first phase of a crude oil loading facility. This latter project will benefit from the shared expertise we have in both our crude oil and NGL Midstream business. Our Redwater fractionator continues to be one of our busiest sites. During 2012, we successfully completed and commissioned an 8,000 barrel per day expansion, which required a 20-day turnaround that was completed on schedule and under budget. Also at Redwater, we are in discussions with customers and are completing the preliminary engineering work to advance our proposed new 73,000 barrel per day ethane plus fractionator. This fractionator will essentially duplicate our existing fractionator, which we're advancing to help ease the anticipated fractionation capacity constraints in the Fort Saskatchewan Alberta area. Also at our Redwater site, Pembina brought the first of 7 fee-for-service caverns into service in September of '12. As well, we expect to bring 2 more caverns into service this month and a third into service in June 2013. Lastly, given the oversupply of propane in both Western Canada and North America and the associated pricing imbalance, Pembina is investigating opportunities for offshore propane export options that will leverage our existing assets and help provide a solution for Canadian producers. That brings me to our Oil Sands & Heavy Oil business. In 2013, Pembina plans to spend approximately $45 million to increase capacity on Nipisi and Mitsue Pipelines by 12,000 barrels per day and 4,000 barrels per day, respectively, while also increasing connectivity in the Edmonton area. Pembina continues to actively work with customers on identifying oil sands and heavy oil-related solutions. With the acquisition of Provident, we have an increased -- we have increased our access galleon supply and can offer customers condensate and butane products from various sources, including Pembina's Conventional systems, our Redwater fractionator, not to mention both rail imports and truck racks. Before I open it up to questions, I'd like to finish off with a brief overview of our financing activity for 2012. As I mentioned earlier, following the close of the acquisition, Pembina increased its monthly dividend rate by 3.8% to $0.135 per share per month or $1.62 annualized from $0.13 a share per month or $1.56 annualized. This marks the ninth dividend increase since Pembina started trading publicly in 1997. Pembina is currently in a strong -- position of strong liquidity, with cash and unutilized debt facilities at December 31, 2012, in excess of $1 billion. We believe that we will have the access to capital markets to fund our growth projects, and we have reinstated the DRIP to assist with the funding of our 2012 and 2013 plans. With another great year behind us and kicking off 2013 with the largest aggregate capital spending program in the company's history of $955 million, times have never been so exciting for Pembina. We are looking forward to all the opportunities that lie ahead for us. With that, we can start the Q&A. So Rob, please go ahead and open the line up for questions.

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

I noticed you've seem to have implemented a few more hedges in the quarter. And I'm just wondering if you could give us a sense of your thinking on hedging policy, if it changed or if it stayed the course and this is all incremental?

Yes, I think, Linda, our hedging policy hasn't changed. We're still looking at hedging, potentially, 50% of our supply and sales, and we'll do that on an orderly basis. We do have a hedge position that we inherited from Provident that will roll off at the end of the first quarter. I think -- Peter, remind me that we're sort of about 25% hedged at this stage.

Well, we're actually hedged about 50% of our gas supply cost, and that translates into, I think, just under 30% of the gas supply NGL sales value. But we will -- we're happy with where we are now but we will be -- we'll take the opportunity and hedge additional NGL products if we believe the market price meets within our certain targets.

Great. And maybe on the subject of propane, can you give us a sense of the progress being made on your export initiative and whether that would potentially turn some of the propane pricing into long-term contracts? Or would that be done more on a spot basis and what the timing is on that?

Well, we're continuing to work with our customer here, Linda, and I think those negotiations will continue. I think the schedule that we're looking for is to have something further to say by midyear about what the -- what it might look that in terms of a commercial arrangement. I think our plan is, of course, we are looking for long-term contracts for the sale of propane, and so long-term would likely be something like 10 years would be desirable. There could be some interruptible depending on the supply and takeaway capacity, but that remains to be worked out. But that's a general framework for what we're looking at and progress continues to be made.

Great. And just one last clean-up question on your Midstream crude oil business, very strong. We're into March now. So I'm just wondering if you can give us a sense of what you're seeing for 2013 so far, and if the expectations are that, that will continue to be strong?

I think the -- our expectation for the first quarter of 2013 remains still fairly strong, Linda. I think our forecast for the balance of the year might see us returning to levels that are not quite as strong as the fourth quarter or the first quarter of this year. But that remains to be seen. A lot of it is, of course, dependent on what opportunities there are in the marketplace. And I'd say, so far, so good in terms of 2013, and we look forward with cautious optimism for the balance of the year.

Your next question comes from the line of Juan Plessis.

On the Conventional Pipeline system, you had a really good performance in the quarter, partly due to more volume receipt at a higher toll locations. Now is this a change in volumes -- is this change in volumes at the higher toll locations something you think is indicative going forward? Or do you think it's more of a temporary phenomenon?

Juan, we are experiencing high volumes right across our systems. But I think what we've experienced in the fourth quarter will continue for 2013. In fact, our volumes continue to be very strong for the first 2 months of this year. And we actually -- I think we -- well, we've announced that we're -- apportionment, in certain cases, where we have actually had to restrict volumes or have our customers provide their product to us at locations that we're not facing restrictions. So we're off to a strong start, and I would expect that we'll continue to see that strength in 2013.

Okay, excellent. And in the MD&A, you also talked about this in your opening remarks, about $45 million of capital to be invested in Nipisi and Mitsue Pipelines this year. I thought that in the capital budget, 2013 capital budget, it was $25 million. Is that a change or an increase to that number?

I don't think so, Juan, but we'll confirm that, perhaps off-line.

Your next question comes from the line of David Noseworthy.

Just first, maybe, start on the NGL mix recontracting. I was wondering how that's looking and, perhaps, what opportunities you're seeing to restructure the contract to reduce propane commodity exposure?

Well, David, we're going to take advantage of that opportunity where we can. Certain of the contracts, they've got a term on them which, of course, we have to honor the term and so we won't be able to necessarily restructure all the other contracts. But where we can, we will. And I think given that there is a higher demand for service for fractionations -- for fractionation, it does give us the opportunity to improve the contractual terms for liquids recontracting and also reducing the risk associated with, if you like, the commodity risk associated on the recontracting terms. So we continue to work on it. And again, as these contracts come up, we'll have more to say about it, but for the most part, that is our recontract strategy.

Got it. And then, perhaps, just with regard to the ERCB enforcement issued against Pembina, will that require any additional integrity management costs beyond, perhaps, what Allan had described during your Investor Day?

No, you know what, actually, David, because that enforcement notice -- I mean, it came out, like, I think it was last week or so on. I mean, essentially, we had responded to the ERCB in 2011 so it's been, for the most part, it's a -- I'd say it's a done deal. The only exception is that what we are still looking at will be -- and we have assessed areas that we considered the type of frac-ing that occurred on this pipeline -- our pipeline, we've looked at other areas in the organization and we think we've got those covered off. But we haven't got -- the tools haven't been developed to the point where we actually can develop tools. So we're looking at options there as whether we can use the tool or whether we can go in and look at areas that we predict these events to occur and actually test to see if they do occur. But in response to your overall question about integrity for the future, I don't see this having a material impact on Pembina's integrity programs. We've started those. They are obviously higher than they have been in the past and largely related to ensuring that we have appropriate levels of integrity on the system before we start running at the higher pressures that we anticipate starting later in 2013, and of course, as we complete the expansions in 2014 as well.

One last question, in light of a recent announcement of the environmental impact statement for Keystone XL coming out, seeing positive, I was just wondering what opportunities you see for Pembina should Keystone XL be approved? I mean, are there any prospect of projects that are being held up as a result of the approval, or delay of approval right now?

David, I'm not aware of any that are being held up as a result, but I think generally speaking, the industry needs to see a green light there because I would suspect that a number of producers in the oil sands have been watching with some, obviously, concern initially and hopefully, with some optimism now that will allow their projects to proceed. But I think the more important matter is that the product has been discounted so significantly in Western Canada that we do need to see additional export capacity, and Keystone is the first phase. We need more export capacity to be able to narrow those differentials. So I think that's kind of where, I'd say, the producers are watching, David. But I can't speak for any specific project that's being held back as a result of Keystone not coming onstream, but it's clear we need more export capacity.

Just one last question, maybe, in relation to opportunities as -- perhaps, as a result of this discount that we are seeing in the oil. You spoke a bit about the PNT and truck terminal-ing, storage, as well as rail loading, accrual rail loading. I was wondering if you could give us just a bit more color around what kind of capacities you're hoping to be shipping on your rail loading facility?

David, I don't have a good number for you at this stage. We'd have to get back to you on that. I was thinking, roughly, and I could be wrong here -- Scott, maybe will say -- about 40,000 barrels a day is kind of what we're looking at.

The next question comes from the line of Robert Catellier.

Just a follow-up on the questions on the oil differentials, so obviously, a very strong quarter. I'm wondering if you could help us apportion the success and the strength you've had there between the wide heavy oil price differentials and the volume strength that's coming off the Conventional system.

Rob, good question. That would require a little bit more work on our part. I just don't have an answer for you. So perhaps, can we take that off-line and provide you at least some sort of sense as to volume variance versus price variance?

Sure. And a follow-up question there. My understanding is that, generally speaking, you're leveraging your infrastructure to effectively make money off the price differentials more so than the locational aspect. So I'm wondering if -- to follow up on David's question, what you're doing to help your customers ease the pain of the locational differentials that go along with the situation we're seeing here, why the differentials, in part, due to lack of infrastructure? So you gave a number of 40,000, I think, it was for the volume there. Is there any way to grow the rail capacity or develop the U.S. assets to help your customers reduce the wide oil price differentials?

Rob, that's a level of -- probably, a level of detail that we haven't really turned our attention to. I think, generally speaking, we are trying to respond to the pain that our customers are receiving wherever we can by mostly providing additional transportation services. And it's going to be a couple of years before we can develop an export -- propane export solution for our customers as well, which I think will be very helpful. But generally speaking, the market differentials that exist today, they're driven off of factors that we have little in the way of control over. All we can do is kind of respond to the opportunities as they present themselves, which we'll continue to do. So we'll take -- we'll look at the price volume variance that you've asked us to look into, and we'll think further about your question on how it is that we can change or, if you like, our infrastructure services to better suit our customers. But I -- what I can tell you is that we are doing, essentially, all we can do right now to respond to the conditions that are facing our customers, because right now, there's going to be a lack of, for example, lack of contracting capacity for fractionation because the new product's coming onstream and that product is often coming in onstream under long-term contracts that are committed to not only fractionation capacity, but pipeline capacity as well. So the game has changed. The circumstances are clearly different today than they have been historically. I think, historically, people just always assumed there was going to be fractionation capacity and transportation capacity. But as you know, we're spending close to $900 million to respond to those sort of requests, plus, we're looking at putting in new fractionation capacity. So we're trying to do a lot to help our customers out, but unfortunately, it takes time and it takes money, it takes commitment. So those circumstances are different.

Great. So it sounds like the message I'm getting from you here is it's still evolving. You're doing what you can, but it's still evolving and who knows, we might hear about new opportunities in the future?

That's right.

Just on the commercial services aspect of Provident, understandably, that's a little bit less transparent under the new reporting of your larger organization. But if I were to look through the numbers that were provided with the press release, it looks to me like those results, they have been down a little bit year-over-year. So I was wondering if you could provide the operating margin for the commercial services aspect and maybe comment on the business conditions there.

Rob, that's something, again, we'll have to take off-line because I just don't have that detail in front of me. So can we get back to you on that as well?

Right. But just maybe comment on the business conditions. Has anything changed there, or is it...

Scott, do you -- are you seeing anything different there?

No, Rob, we can reconcile off-line because I don't think that it's down. In fact, it's up. We've added, obviously, a new storage cavern in Q4 of 2012. And as Bob mentioned, we have 2 new caverns coming in, in March and 1 in June so I would say, they're as good as ever there.

Okay. And then, my last question has to do with the scope change at Resthaven. So that's obviously, going to move the timing of that project. But can you talk a little bit about the scale of change and the nature of the change that might happen there? And what I'm trying to decipher is if there's any new services being offered and if there's just really scope change or if there's any cost escalation.

I'll let -- I'll have Scott answer that question, Rob.

Yes, Rob, right now, it's truly at request of the customers to add some new liquids handling capability and some additional services. I can't get into it because it has not been approved by the partners there yet. But we're looking at additional capital up to $35 million. But the point that I'd leave you with is additional capital will be compensated through a fee formula.

Your next question comes from the line of Matthew Akman.

On Empress, maybe you can just characterize in the quarter how you saw the environment for premiums and how much the old hedges, I guess, were still impacting you. And then, I guess, a lot of those will start rolling off after the first quarter. So maybe talk about this year to the extent you can, in terms of outlook there.

Yes. Matthew, we really can't talk about extraction premiums in Empress because it is a competitive -- obviously, a competitive environment. I think it's fair to say we had a fairly decent quarter in the fourth quarter of last year, and I think we're looking for a fairly decent quarter for the first year, which is sort of the way it normally goes. Inventory levels are down now so kind of where to they are expected to be normally. So I'd say that maybe we are into more of a normal year. We do have, as you've identified it, there's a hedge coming off here at the end of the first quarter. And Peter, I don't know if you have any color that you can provide on hedging, overall, as it applies either Empress or otherwise? Maybe I'll just leave that to you.

So I think with the fact that both the supply side and the gas side and propane sales side -- the fact that we were in a little bit, quite a bit of an imbalance during 2012 with us hedging a larger component of the gas supply volume at a very high price. And although we did hedge quite a bit of propane volume, it wasn't quite a match to the gas supply volume. So that imbalance will help us once these contracts expire at the end of March, and we'll have a more balanced hedging portfolio going forward.

Yes, I think the only other color I'll offer there, Matthew, is that propane prices, I think there's an expectation that propane prices will recover somewhat because of the additional export capacity that's being developed on the -- out in the Gulf Coast. But having said that, actually the propane pricing in Eastern Canada, actually, improved for us in the first quarter, because there seemed to be a shortage of supply. So our pricing at Sarnia, for example, was higher than Mont Belvieu. And so that was an encouraging sign for us for the first quarter, but longer term, it remains to be seen. I think our people have a sense that propane pricing will recover. Do we know whether it's going to recover to historic levels? We don't know. That's why our focus is trying to find a solution for propane pricing from Western Canada that will improve the outlook for our producers based on finding or getting access to markets that are more favorable markets.

That kind of ties into my follow-up question on the possibility of the export terminal off the West Coast. And I'm just wondering what you see as the key success factor there. Is it having a counterparty overseas tied up? Or is it having the actual physical product available to deliver? Which one is more important, do you think?

I think the -- and certainly we've got a buyer, is probably the most important, Matthew. Like if we -- once this -- I'm seeing the positive tone. Once we develop our Redwater fractionator, the second fractionator, we're going to have product coming off of that, there's product coming off the existing frac. We think there's going to be sufficient supply to meet the demands of our customer and those demands -- so I think it's really, get the customer first and the product will find its way to a preferential market.

The next question comes from the line of Robert Kwan.

If I can just follow up on the Resthaven answer there. So you kind of described it as a potential scope change. So if the customer decides not to make any of those changes, is the timing back into the beginning of '14?

I think it's going to be -- it'll move up a bit, Rob, or I think it's going to be about that. Scott, do you have anything you can add there?

Yes, Rob, I think you can just assume that it's going to go ahead.

Okay, okay. Just on the Conventional Pipeline results. Just wondering, with the good results, was there anything in the way of toll increases that impacted the quarter, if we think about it sequentially versus Q3? And then, as well, and I don't know whether this would've factored into Conventional Pipeline or Midstream, but were there -- or do you have material, kind of, your own volumes or your own capacity commitments and given constraints, the ability to our -- some of the locational differentials?

That's not something we do. But just to respond to your first question, Rob, the fourth quarter was not impacted by any toll increases. We have increased tolls on some of our locations in 2013, or we're about to increase our tolls, Peter -- as a result of the increased capital that we're putting in for the expansions and new connections. So there will be some toll increases. Peter, do you have a sense, overall, what we're looking at?

No, they'll be certainly in the, I think, the low to mid single-digit type increase. They're fairly selective on the pipes that we -- we have some high-integrity expansions [ph] on and pipes that we're -- with a fairly substantial capital program.

Yes, so there will be some, Rob. And probably, you'll get a flavor -- but it might take you through the -- Robert, through the first quarter before we actually start and have an effective implementation of those toll increases. That isn't anything that we're trying to do to take advantage of any particular location to say, for example, move higher toll volumes. That's not something that we target to do. We take and we move all the volumes that we can. And the apportionment often is based off of the previous -- an average of previous production from facilities. So I think it's fair to say that we're probably going through a period of time here where the producers are going to be impacted by pipeline capacity restrictions. And of course, in some cases, those restrictions are downstream of Pembina as well. So it's a different environment for us, for sure, in the sense that volumes continue to be strong, and we're trying to accommodate our customers the best way we can.

Just the last question I have relates to Empress and just the ownership structure there. There's some comments in respect to that, they've got some optimism that, that we'll see some rationalization there in 2013. Just wondering your thoughts on that, and whether you'd be -- based on your assessment now that you've have the assets for a year, would you be willing to get bigger to help Empress get smaller?

Good question. I think there's a couple of ways to look at that. But personally, I think our position right now is probably, we've got one of the newer facilities there. So to increase our ownership of the facilities that, perhaps, are uneconomic might not make an awful lot of sense to me personally. But that remains to be seen, Robert. So Empress, it continues to be an area that we've got to continue to watch. Fortunately for us, because we're a bigger company now, it probably is not as significant to the overall consolidated business as perhaps, it would've been to Provident on a stand-alone basis. And we have to see what other developments are going to take place before we sort of look at what we'll do longer term at Empress.

I guess, just to kind of recap, Bob, you don't see a great rationale, given your position, but you certainly haven't ruled out the possibility of being the consolidator?

I believe we've ruled that out, Rob, but we have to have -- there's got to be -- by interest by lots of parties there to make that happen. And so far, I don't think -- I don't know that the interest is necessary there at this stage. That's something that needs to be determined.

Your next question comes from the line of Steven Paget.

You had spent $349 million as of December 30, and spent $255 million in the fourth quarter. But your cash flow to investing was $547 million. Was there an asset sale of any kind?

No. That's likely an old venture, that's probably about $40 million of accruals at year end relating to capital. We've actually -- the work has been done but we haven't paid for the services this year. So that's probably the difference that you're looking at there, Steve.

On Gas Services, your premium net margin in Gas Services was really high in the fourth quarter at about $0.66 a unit, and it came down to $0.57 in the fourth quarter, which is right back to the run rate of where it had been. Can you fill us in on what happened there?

Steve, I think we're probably going to have to get back to you on that with something specific unless, Scott, you've got -- these numbers in front of him, but they're way too small for me to see. So perhaps, we'll have to respond to that question later this morning, Steven, if that's okay.

Steven, that was just some adjustments in the fourth quarter for previous years, so it was just kind of catching up on some payments and other things. So pretty minor, overall.

The next question comes from the line of Chad Friess.

Question on the proposed 73,000 barrel a day expansion at Redwater. Generally speaking, are the current fees for frac service in the markets sufficient to meet your hurdle rates on that project? Or is the cost of new entry for a big project like this higher than where the current market sits?

Good question. I'd have to say that what we're targeting for returns are based on the capital that we're going to invest on a new fractionator, and I would think that those are -- those results are going to be acceptable to our customers. So I don't think we're going to see an appreciable variance in the fees that are going to be charged for that overall level of service.

Okay. And so if it's not pricing, then what are the main talking points in your efforts to secure commercial commitments? I guess, what do producers need to see to commit their volumes at the fees that you're looking at?

Well, there's a couple of things. Of course, there's -- we need to expand our pipeline capacity to handle higher volumes of HVP. There needs to be an offtake arrangement as far as commercial terms for the ethane. And basically, I think those are the factors that people have to look to. And I think it's fair to say that we're close on all of the factors that are required for the fractionator.

[Operator Instructions] Your next question comes from the line of David McColl.

Just to move back to rail, I have 3 related questions. I'll just shoot them all out at once here. I'm just wondering if you can provide some additional comments on that 4,000 barrel a day rail potential you've mentioned. Particularly, I'm just curious in terms of the level of interest you're receiving regarding that. And just to kind of follow up on that as well, I'm wondering what -- any insights you might have in terms of the end markets for these barrels, in particular, if there's a focus on moving these towards the Gulf Coast? And just the last question for you, I'm just wondering if you have, like, what your view is in terms of the near term, let's say, 2-year outlook versus a 5-year outlook on rail given the planned expansions we're hearing about to the North American long-haul pipe system?

Well, in terms of level of interest, I think it's fair to say we are working with a customer -- customers on service that Scott has alluded to with respect to moving product out, and I think it really would relate to oil initially. As far as the end markets are concerned, you know what? I can't really comment on those -- where the end markets are for the product. I think it's based on our customers to make their own commercial arrangements as to where they would like to see the product to go, it'll be based on where -- they may have their own other interests that will allow them to maximize their net backs based on other facilities or other commercial arrangements that they can make. And as far as near-term versus longer-term view, certainly, the near-term view, I think, is going to be strong for utilization of rail because there's a lack of pipeline capacity and the large differentials will continue until we get more export capacity. But if you look 5 years from now, if we get some pipelines built, will that mean rail disappears? I don't think so because I think there's going to continue to be a market for some product to move to locations that it otherwise couldn't get to. So I say, rail is around for the longer term. Will the utilization in 5 years be as high as it will be the next 2? That, I can't really comment on, but I still think it's going to be there.

There are no further questions at this time. I will turn the call back over to Mr. Michaleski.

All right. Well, thanks very much for those who have participated in the call this morning. Obviously, we're pretty encouraged by what we're seeing in the infrastructure space and the challenge that we're going to have is trying to provide as much in the way of capacity for our customers going forward, and that's something that we'll have more to say about soon. And so we look forward to being able to, again, to try to respond, continue to offer the services that we can and provide safe and reliable pipeline transportation for our customers. So thanks, again, for participating and we'll be talking again soon. Bye now.

Ladies and gentlemen, thank you for your participation. This concludes today's conference call, and you may now disconnect.