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Pembina Pipeline (NYSE:PBA)

Q4 2013 Earnings Call

February 27, 2014 9:30 am ET

Executives

J. Scott Burrows - Vice President of Capital Markets

Peter D. Robertson - Chief Financial Officer and Senior Vice President

Michael H. Dilger - Chief Executive Officer, President and Director

Analysts

Juan Plessis - Canaccord Genuity, Research Division

David Noseworthy - CIBC World Markets Inc., Research Division

Carl L. Kirst - BMO Capital Markets U.S.

Linda Ezergailis - TD Securities Equity Research

Robert Kwan - RBC Capital Markets, LLC, Research Division

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

David McColl - Morningstar Inc., Research Division

Operator

Good morning, my name is Jeremy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation 2013 Fourth Quarter and Annual Results Conference Call. [Operator Instructions]

Thank you. Mr. Scott Burrows, you may begin your conference.

J. Scott Burrows

Thank you, Jeremy. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our 2013 fourth quarter and annual resorts. I'm Scott Burrows, Pembina's Vice President of Capital Markets.

For this morning's agenda, we will start with Peter Robertson, Senior Vice President and Chief Financial Officer, to spend a few minutes reviewing our fourth quarter and annual 2013 results, which we released yesterday after markets closed, and then turn the call over to Mick Dilger, President and Chief Executive Officer, to provide an update on Pembina's business developments. Following that, I will discuss our recent financings, and then Mick will provide closing comments before we 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 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 and additional GAAP measures.

To learn more about these forward-looking statements, non-GAAP and additional 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 expressed or implied today. Please, go ahead, Peter.

Peter D. Robertson

Thank you, Scott, and good morning, everyone. Both our financial and operating performance during the fourth quarter and full year of 2013 were very strong. I am pleased to report that Pembina delivered another solid quarter, and that 2013 resulting in the most successful and exciting year in Pembina's 60-year history.

In 2013, not only did we begin to realize the benefits from the 2012 acquisition of Provident, we also announced the largest pipeline expansion plan in our history, bringing the total estimate of new growth projects secured during 2013 to $3.5 billion. We did all of this while also continuing to operate our business safely and reliably. We increased sustainable cash flows by placing $1 billion of assets into service and increased our dividend, driving long-term, reliable returns and maximizing value for our shareholders. Pembina remains committed to delivering on our promises and building out a suit of growth projects over the years to come.

At a high level, our strong financial and operating performance was positively impacted by several factors. These include higher propane prices, which benefited from our -- our Midstream business, and increased volumes in our Conventional and Oil Sands Pipelines as well as in Gas Services, due to higher customer activity in our operating areas. New assets and expansions in our businesses also contributed to higher volumes.

In the fourth quarter, adjusted EBITDA increased by 18% to $235 million from $199 million in the fourth 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. On a full year basis, adjusted EBITDA increased by 41% to 3 -- $831 million, up from $590 million in 2012 due to the same reasons I just mentioned and due to a full year's contribution from Provident, which closed April 2012.

Adjusted cash flow from operating activities increased almost 5% to $180 million during the fourth quarter of 2013 relative to the same period last year when adjusted cash flow from operating activities was $172 million. Annually, the jump in adjusted cash flow from operating activities is even more impressive. We saw an increase of almost 46% from $494 million in 2012 to $720 million for 2013. Per share, this increase was just under 23%.

For our Conventional Pipeline business, average throughput increased by 4% during the quarter and by 8% for the year compared with the same periods 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. However, it's worth mentioning that there are many systems -- that many of our systems were essentially running at full capacity throughout 2013, and we didn't see a substantial increase in volumes until later in the year when we brought our Phase I crude oil condensate and NGL pipeline expansions into service. Our average throughput for December was almost 540,000 barrels per day, 9% higher than the 492,000 barrels per day average for December 2012.

Conventional Pipelines increased revenue by 12% during the fourth quarter of 2013 to $111 million compared to $99 million in the same period last year. For 2013, revenue increased 21% to $411 million, up from $339 million for 2012. These increases were primarily due to stronger volumes, new connections and the Phase I expansions as well as the reassignment of a pipeline segment from Midstream to Conventional Pipelines at the beginning of the year.

Offsetting higher revenue in Conventional Pipelines was operating costs, which increased 24% and 25% for the fourth quarter and full year, respectively. Increases were largely as a result of our ongoing pipeline integrity work, seasonal winter-access pipeline work, higher product costs related to volume growth, and higher expenses for power and labor.

Fourth quarter operating margin was virtually unchanged due to a proportionate increase in operating expenses relative to revenue. Full year operating margin grew over 20% to $251 million compared with $209 million from 2012 due to higher revenue associated with growth volumes.

Our Oil Sands & Heavy Oil business also generated improved results. This was largely due to higher volumes on the Nipisi Pipeline. Our operating margin increased 10% for the fourth quarter and 12% for the full year 2013 compared with 2012 periods.

Gas Services increased 44% in average processing volumes to almost 400 million cubic feet per day during the fourth quarter compared with 276 million cubic feet per day in the same period last year. On a full year basis, volumes increased 16% to 319 million cubic feet per day compared with 275 million cubic feet per day in 2012. This growth was caused by volumes from the Saturn I facility.

Placing Saturn I facility into service during the fourth quarter of 2013, higher processing volumes increased fees associated with capital reinvested at the Cutbank Complex and greater recovery of operating expenses increased revenue in this business by 43% and 38% for the fourth quarter and full year 2013, respectively. Offsetting this revenue increase were higher operating expenses, which were largely a result of power, operating labor and maintenance costs associated with new assets being placed in service as well as higher volumes and increased activity at the expanded Cutbank Complex.

Overall, operating margin in Gas Services increased by 50% and approximately 32% for the fourth quarter and through -- and for 2013 full year compared to the same periods last year.

Midstream also had another successful quarter. Our NGL Midstream activities generated excellent results. Operating margin for the period increased over 54% compared to the same quarter last year, and NGL sales volumes during fourth quarter of 2013 were almost 122,000 barrels per day, a 5% increase compared to the fourth quarter of 2012. This increase was driven by higher sales in ethane and butane product sales.

Our Redwater West assets, in particular, benefited from a stronger year-over-year propane market, bringing an increase in operating margin during the fourth quarter of about 48%.

Similarly, express -- Empress East operating margin increased substantially by 176% to $47 million over the fourth quarter compared to the same period last year. This increase was due to stronger year-over-year propane markets and lower inventory acquisition costs driven by lower extraction premiums.

Moving to our crude oil-related Midstream activities. Operating margin increased over 6% during the fourth quarter of 2013 compared to the same period last year due to stronger margins and new services, such as crude oil, unit train loading as well as improved volumes at Pembina's truck and full-service terminals during the quarter.

On a full year basis, higher volumes and increased activity in 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 and crude oil unit train loading services resulted in an increase in operating margin of over 11%.

On a consolidated basis, results of the businesses were very positive. Fourth quarter and full year 2013 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 will now turn the call over to Mick Dilger, who will give an update on our business activities.

Michael H. Dilger

Thanks, Peter. Good morning, everybody. I'll now provide a relatively brief update on our growth projects, starting with the Conventional Pipeline business.

On December 16, 2013, we announced having reached binding commercial agreements to proceed with constructing approximately $2 billion in pipeline expansions, which we're calling the Phase 3 expansion of our key system. This expansion will be the largest capital project we have ever undertaken in our history and will be a transformational event for Pembina, setting the stage for future growth.

Phase 3 is underpinned by long-term take-or-pay transportation service agreements with 30 customers in our operating areas and is expected to be placed into service between late 2016 and mid-2017 subject to environmental and regulatory approvals. The 540-kilometer Phase 3 expansion will follow and expand upon certain segments of our existing pipeline systems from Taylor, British Columbia, southeast to Edmonton, Alberta, with priority being placed on segments of pipelines where debottlenecking is essential.

The core of the Phase 3 expansion will entail constructing a new 270-kilometer, 24-inch-diameter pipeline from Fox Creek, Alberta, to the Edmonton area, which is expected to have an initial capacity of 320,000 barrels per day and an ultimate capacity of over 500,000 barrels per day with the addition of midpoint pump stations. Once complete, we will have 3 distinct pipelines in the Fox Creek to Edmonton, Alberta, corridor. Each will be constructed separately.

With our existing pipelines and current expansions, the Peace and Northern systems are expected to have the designed capacity to transport of approximately 1 million cubic -- 1 million barrels per day if fully expanded. The Phase 3 expansion also contemplates increasing pipeline interconnectivity between Edmonton and Fort Saskatchewan, including our Redwater and Heartland Hub sites as well as third-party delivery points in these areas.

To date, we have begun consultation with communities, stakeholders and first nations regarding the Phase 3 project proposal, have commenced land acquisitions, and we expect to file regulatory applications in the third quarter of this year, all in communities where we have operated for a long time.

We are also continuing to proceed with our earlier announced $115 million Simonette Pipeline Expansion as part of the Phase 3 project between Simonette and Fox Creek, Alberta, which is expected to initially deliver 40,000 barrels per day of liquids to our Fox Creek Terminal and will access our Phase I and Phase 2 Peace expansions. Regulatory and environmental approvals have been received, and construction has begun with an expected in-service date in the third quarter of 2014.

In December 2013, we also completed and commissioned our Phase I NGL expansion, which increased NGL capacity on our Peace and Northern Pipelines to 167,000 barrels per day. We are continuing to progress with our previously announced Phase 2 expansion plans, which will further increase NGL capacity to 220,000 barrels per day by mid 2015.

Also during December, for our crude oil and condensate expansions, we completed and commissioned our Phase I expansion, bringing an additional 40,000 barrels per day of crude oil and condensate capacity onto the Peace Pipeline.

Further, we continued to progress our Phase 2 expansion, which will increase capacity to 250,000 barrels per day and expect it to be complete by late 2014, again, subject to regulatory and environmental approvals.

By the end of 2013, we also brought into service 8 clean crude oil and condensate truck unloading risers at our Fox Creek Terminal to help facilitate trucked-in volumes to access Edmonton area market through our Peace Pipeline mainline expansions.

Now I'm going to speak on the Oil Sands & Heavy Oil business unit. In our Oil Sands & Heavy Oil business, during 2013, Pembina completed an additional pump station on the Nipisi Pipeline, which increased capacity to 105,000 barrels per day as well as an additional pump station on the Mitsue Pipeline, which increased capacity to 220 -- to 22,000 barrels per day.

We also continued to move forward with work related to our previously announced $35 million engineering support agreement for the proposed Cornerstone Pipeline and have increased the estimated costs to approximately $1 billion in 2014 dollars, up from $850 million, which we quoted in 2010 dollars, due to labor inflation and refining of the project scope as we advanced with development and preliminary engineering.

Gas Services. As announced in October, our Saturn I facility was completed and put into service, coming in on budget. The Saturn I facility is a 200 million cubic feet per day deep-cut processing plant, which has the capacity to extract up to 13,500 barrels per day of NGLs, which we have exceeded and hit peak rates of over 14,500 barrels per day. The plant's liquid recovery is coming in ahead of expectations and is currently seeing throughput of 180 -- 198 million cubic feet per day but has processed feed gas rates of 220 million cubic feet per day.

With respect to our other previously announced projects, the fully contracted Resthaven gas plant is still on track to be in service by the third quarter of this year with over 50% of the construction now complete and all long lead equipment items ordered.

As mentioned in August, we are now -- we are continuing to construct Musreau 2, 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 2 is designed to handle propane plus and is expected to yield around 4,200 barrels per day of NGL for transportation on our Conventional Pipelines. All long-lead equipment has been ordered with a targeted in-service date of the first quarter of 2015.

Lastly, we are continuing to construct -- construction for Saturn 2, which is a 200 million cubic feet per day, twin of Saturn I. With over 65% of long-lead equipment ordered, we expect the facility to be in service late 2015. Saturn 2 will leverage engineering work completed for Saturn I and is expected to cost $170 million. The Saturn 2 facility is designed to 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 onto our Midstream business. We continue to see growth opportunities aimed at increasing optionality for our customers in the Midstream space. Our largest project in this business, as announced before, is a 73,000 barrel per day fractionator, RFS 2, which we are constructing at our Redwater site. Construction is currently tracking on time and on budget, and we expect RFS 2 to come into service in the fourth quarter of 2015.

As mentioned during the last call, we also completed land acquisition in the Alberta Industrial Heartland, we call the Heartland Hub, which will be a further build-out of our larger Nexus Terminal. The site features existing rail access and utility infrastructure to support the future development of rail, terminalling and storage facilities.

We also entered into a multiyear agreement with a North American major refiner for loading up to 40,000 barrels a day of various crude grades onto -- crude oil rail cars at our Redwater facility. We began moving unit train outbound deliveries in October 2013 as part of a phased expansion of terminalling services that we're building out at our Nexus Terminal.

I will now pass the call back to Scott to give an update of our financing.

J. Scott Burrows

Thanks, Mick. During 2013, we executed a successful financing program to fund our ambitious growth plans, raising 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. We also issued $200 million in 30-year notes and raised $345 million in common equity. On January 16, 2014, we closed our third preferred share offering for gross proceeds of $250 million, bringing our total financings rate to $1.2 billion over the past 12 months.

At the end of 2013, Pembina has just under $1.5 billion of -- unutilized debt facilities available and approximately $51 million of cash. We continue to have a healthy balance sheet with access to capital and the appropriate flexibility required to build out our growth plan and accomplish our goals. Pembina is well established to continue delivering superior and improving results for our shareholders going forward.

I will now turn the call back to Mick.

Michael H. Dilger

In closing, looking back at what we have accomplished in 2013, I'm very pleased to have finished the year off with record financial and operating results. Having begun my first year as President and CEO, I'm excited for the future and believe we have set the foundation with the right strategy and people in place to continue delivering similar results through 2014 and beyond just as we have in the past. Pembina remains committed to safe and reliable operations and maximizing long-term sustainable value for our shareholders.

As a reminder, we will be hosting our 2014 Investor Day in Toronto on March 5 starting at 8:30 a.m. Eastern Time. We will be webcasting the event, so, please, go to our website for further details to register or email our Investor Relations team if you'd like any further information on the event. Our executive team is looking forward to providing a thorough review of our company and our strategy.

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

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Juan Plessis from Canaccord Genuity.

Juan Plessis - Canaccord Genuity, Research Division

Wondering if you might be able to update us on any discussions that you may be having surrounding agreements for the 25% of Phase 3 pipeline expansion capacity that remains uncontracted?

Michael H. Dilger

Nothing specific to say on that. There certainly is additional interest. We didn't totally blanket the industry with the first go around despite our intent to do so. But yes, we feel confident there'll be additional volumes signed up before we have to make the ultimate pipeline sizing decision. But nothing to report specifically at this time.

Juan Plessis - Canaccord Genuity, Research Division

Okay. Would it be fair to say that you're a bit more optimistic now than you were when you first announced the project?

Michael H. Dilger

I wouldn't say we're -- I'd say we were optimistic even when we announced the project. There will be additional volumes, and we remain equally optimistic there will be.

Juan Plessis - Canaccord Genuity, Research Division

Okay. Moving to something a little bit more micro. The G&A cost in the quarter bumped up about $13 million from the previous quarter. And I know it's mentioned that part of this was due to share-based incentives. But based on the sensitivity for increases in share-based incentive expense, it doesn't appear that a lot of the increase is attributable to this. Can you tell us what contributed to the jump in G&A and if there's anything onetime in nature and also if $43 million is a good quarterly run rate to use?

Peter D. Robertson

Yes, certainly, we provide for our STIP/LTIP program throughout the year. Every quarter of the year, we set aside something in G&A. So certainly not the whole program goes into the fourth quarter. Although the fourth quarter is very closer to the end of the year, see what our results will be, the impact of our share price appreciation and all gets finalized in the fourth quarter. There are no specific large items in the fourth quarter that we should bring to your attention. And the last part of your question was regarding a run rate of 40 -- what was your number?

Juan Plessis - Canaccord Genuity, Research Division

I think you reported $43 million of G&A.

Peter D. Robertson

That was in the fourth quarter. So there is -- maybe that's not a good run rate on a quarterly basis. You're better off taking the annualized -- the annual number and using that on a go-forward basis.

Operator

Your next question comes from the line of David Noseworthy from CIBC.

David Noseworthy - CIBC World Markets Inc., Research Division

First question is just with respect to your Cornerstone Pipeline. Statoil and PTTEP have recently swapped their KKD assets. Do you expect this change in ownership to have any impact on the required pipeline size, decision to move forward with Cornerstone or the time for FID for the KKD project?

Michael H. Dilger

The -- we've been saying that we expect to announce something this calendar year. We remain on track for that. I think this is a little bit of short-term pain for long-term gain. It's -- there's no question they have to close that deal before they say anything. But we view the simplicity of that deal to improve after this transaction, and in the long run, a good outcome for us. So perhaps a quarter delay in sanctioning, but we still expect to announce something this year. It's our hope that we can announce something this year.

David Noseworthy - CIBC World Markets Inc., Research Division

Okay. So previously, I think the partnership had mentioned a kind of a March 31 Q1-type decision timeline. So now we're looking at something closer to the end of Q2?

J. Scott Burrows

Well, David, I think that it would be foolish for us to comment on when that deal may close. And I think you can assume that FID won't be received until that transaction closes. So really, we're at the mercy of the competition bureau and other factors.

Michael H. Dilger

The only thing, David, I would add is that we've been given clear instructions by Statoil to not allow the project to slip. So we have the $35 million ESA. We're -- they've given the instructions to keep moving full speed ahead. So from our perspective, nothing's changed.

David Noseworthy - CIBC World Markets Inc., Research Division

All right, that's encouraging. And then in terms of your Conventional Pipeline, I was wondering if you could just talk about -- there's a number of things that happened at the very end of the quarter being the Phase I expansions and your 8 unloading risers. Do you have a Conventional Pipeline system throughput volume exiting the quarter?

J. Scott Burrows

Yes, David. I don't think we're going to tell -- say at that time. But I think you can assume most of those pump stations came on very early in December. And so we provided the guidance of 540,000 barrels a day in December. So that's a good number. Any one week can have fluctuations so that looking at a one -- a point in time is probably not great, but looking at the month of December is an accurate depiction of volumes.

David Noseworthy - CIBC World Markets Inc., Research Division

All right. All right. Fair enough. And this is a little bit more granular. But in terms of looking at your pipeline, operating expenses increased 10% year-over-year. Power prices were down 38% year-over-year. So is this increase mainly then integrity spend? And what is your integrity spend on pipelines going forward in 2014?

Michael H. Dilger

You're correct. It was integrity. You can imagine the amount of work we had to do to ready the pipelines for Phase I and Phase 2. The Phase 2 expansion readiness is complete. We're comfortable that the pipes can operate at those required operating pressures. I wouldn't say quite that -- we've probably crested in terms of integrity spending on CBU, but it's not going to come down overnight. We still have a lot of work to do through 2014. It starts to taper -- I'm hoping it starts to taper off in '15 and '16. But things happen. I mean, integrity includes geotechnical. And geotechnical is dependent on things like how much rain you get and flood conditions and things like that. And so any severe weather event can add a lot of money to your integrity bill overnight. But all things being equal, I think the highest we'll see in CBU was probably what we saw in 2013.

David Noseworthy - CIBC World Markets Inc., Research Division

I appreciate that color. And maybe I can just move over to your Midstream. Pembina -- has Pembina experienced any propane shortages or logistical constraints in terms of getting propane to market? And I guess I'm more focused on the Empress East segments in Q1.

Michael H. Dilger

Everything we've produced, we've been able to get to market. We wish we had more.

David Noseworthy - CIBC World Markets Inc., Research Division

Yes, absolutely. And I guess -- and that kind of comes to my next question, which is in the MD&A, you attribute higher NGL sales volumes to ethane and butane but not propane. I was just wondering why that was the case.

Michael H. Dilger

Because, I mean, we sold the same amount of propane last year as we did this year. We can't produce any more than we have, David. So basically, volumes on the propane side are relatively flat.

David Noseworthy - CIBC World Markets Inc., Research Division

Okay, so you just sold everything you had both years. So it is what it is. Got it. And then last question. Empress [ph] on your propane differentials. What is your outlook for that going into 2014?

Michael H. Dilger

Whatever your outlook for the weather is. No, David, obviously, they're very robust. But I think we expect them to return to somewhat normalized level as inventory -- as we move into the summer months. We're not smarter than the market.

Operator

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

Carl L. Kirst - BMO Capital Markets U.S.

Maybe just going back to the Phase 3 expansion for a second. Can you help remind me of the initial 75% that's contracted, what return or EBITDA you're targeting secured with just that amount?

Michael H. Dilger

Yes, David, I believe the press release -- sorry, Carl, I believe the press release was $275 million to $300 million of EBITDA on a runway basis.

Carl L. Kirst - BMO Capital Markets U.S.

Great. And so as we potentially add more to that, and I think you kind of touched on this, and as much as it perhaps will be dependent on how much additional commitments come in with respect to what the final size of the pipeline system is going to be. But I guess we were trying to get a sense of what incremental contracts acceptably go towards either increasing the return of the project, the higher EBITDA multiple, if you will, versus, perhaps, leading just outsizing the system, meaning greater invested capital? And I might be answering my own question here, but I guess at this point, is it just -- it's going to be dependent on what the level of commitments that come in? Or is the real goal here to expand that to that larger capacity you noted?

Michael H. Dilger

The way I would answer it, if we had a pleasant surprise in people signing up over the next number of months, our ideal end state would to be that 4 pipelines between Fox Creek and Edmonton, not 3, because we have 4 distinct products to move. So if we had a pleasant surprise, we might actually downsize the 24 to a 20 and add a 16 so that we could get to that end state. In absence of that, we think the best way to look into the crystal ball in the future is to run with the 24. I think that's the most likely outcome. But in our perfect world, let's say we've got an extra 100,000 barrels a day, which would be a pleasant surprise, before we have to make that final decision, we might actually go to the 2016 so that between Fox Creek, we have condensate, crude, C2+, C3+, all coming down uninterrupted.

Carl L. Kirst - BMO Capital Markets U.S.

Excellent, excellent. And as I think about the potential expansion from Edmonton to Fort Saskatchewan, and I guess trying to -- not wanting to put the cart in front of the horse, but the potential of, say, for instance, even an RFS 3, as you get incremental contracts here perhaps over the next 4 to 6 months, is that what you need to perhaps inform you of the RFS 3 path? Or are those not so much linked?

Michael H. Dilger

Well, I think you're right. They could be linked, but just because we haven't announced RFS 3 doesn't mean that the volumes don't exist in the pipeline commitments that we've been given. I think it's fair to say that producers had a lot to chew on, making the kinds of commitments they did to our Phase 3 pipeline. And so they had a little bit of a breather, and now they're assessing the next step down the value chain where that product is going to be fractionated. So I guess what I'm saying is we don't necessarily believe we need additional Peace Phase 3 pipeline commitments in order to move forward with RFS 3. But you're right, directionally, obviously, the more initial commitments we have, the greater the likelihood of people contracting will be.

Carl L. Kirst - BMO Capital Markets U.S.

Excellent. And then last question maybe if I could. You guys ended on a strong note here on the Midstream oil side in the fourth quarter. Recognizing there's always a bit of uncertainty in this number but didn't know if you could give us your thoughts for where you thought Midstream oil might be able to shake out for 2014, if you could meet or even exceed what we've done in 2013 because of now, for instance, oil by rail. But any color there would be appreciated.

Michael H. Dilger

Well, as you pointed out, commodity prices will do what they will do. But we continue to invest in that area, and we, of course, continue to assume we'll have an incremental return on that investment. So as we invest dollars over time, we will expect the returns to be higher. Now any given quarter, who knows how it is? But the guys in the Crude Oil Midstream business have built a terrific matrix of options. And I'm always pleased with the fact that, that business just seems to turn out cash now regardless of what any specific market's circumstance might be. So they've done a great job. Yes, I think they have enough options to generate pretty low volatility cash flow. So generally, if we're spending money, we're going to make more money over time.

Operator

Your next question comes from the line of Linda Ezergailis from TD Securities.

Linda Ezergailis - TD Securities Equity Research

I have a question. Maybe you could help us understand with some of these differentials moving around in propane pricing, and I'm not confident that we're going to get into a steady state anytime soon. Can you give us a sense, maybe loosely, the market mix of pricing that we might generally look towards, realizing that, that can shift around in any given quarter?

Michael H. Dilger

When we look forward, we have no choice but to go with the norms, historical pricing trends. I mean, what we saw in Edmonton and Sarnia being higher than Conway and Belvieu was almost unbelievable. And so that's certainly not what we're assuming in the future. We're off, as you can imagine, to a fast start in 2014. But even for the balance of 2014, internally, we're budgeting more normal prices. We don't see anything out there that would push us off that. The coast in reversal, that could put some pressure on prices, but we are ramping up rail cars to counteract that. How that'll exactly play itself out? We don't know. But Linda, you know what, we have to forecast norms.

Linda Ezergailis - TD Securities Equity Research

Okay. Well, maybe you could help us with our toolkit in the event that there isn't a normal month in December or whatever. How might we think of the disposition of your barrels of propane in terms of ultimate market pricing? Would it be more heavily weighted to Edmonton Sarnia? Or would there be a healthy mix of Conway and Mont Belvieu pricing in there as well?

Michael H. Dilger

Well, Linda, our propane is produced out of Empress, obviously, goes east to the Sarnia market. So our Empress volumes are highly correlated with Sarnia prices. And then our Redwater volumes are obviously highly correlated with Edmonton prices, which traditionally have been correlated with Conway. So you can think about our Redwater West system more on a Conway based and Edmonton based and then our Empress East on a Sarnia-based pricing.

Linda Ezergailis - TD Securities Equity Research

And that won't change as you ramp up rail to more -- a little bit more Belvieu?

Michael H. Dilger

We're trying to just keep everything the way it is. I mean, we don't want to be constrained in Edmonton, and we won't be based on our -- at least our proprietary production forecast. We weren't a big Cochin user, so we'll continue to move barrels as they were. That doesn't necessarily mean others can move all their barrels. And if they can't, it'll put negative pressures on Edmonton pricing.

Linda Ezergailis - TD Securities Equity Research

And just a follow-up question while we're on the topic of NGLs. What was driving the increase in volume in ethane and butane? And might that trend continue? I guess Q1 is 2/3 behind you now, but for the balance of 2014?

Michael H. Dilger

Well, the big change is in volumes were Empress throughputs, I heard yesterday from -- internally, I can't verify this, but efforts -- volumes were around 5 bcf, which is significantly higher than they were last year. And so in addition to that, the liquids composition of those Empress volumes is more variable, i.e., more barrels a million. So those things combined have led to higher volumes at Empress. I can't say that we're expert in forecasting Empress throughputs as they seem to be somewhat gas price sensitive, but I think that's where to look. If you were optimistic on Empress throughputs remaining at 5 bcf a day, you could be optimistic about our Empress operating margin.

Linda Ezergailis - TD Securities Equity Research

Great. Maybe just a question for Peter as well. What's your outlook for cash taxes in 2014?

Peter D. Robertson

I would suggest -- I mean, in 2013, we were around the $37 million, $38 million mark. That's largely a result of our crude [ph] not being -- not fully utilized in 2013. So going into 2014, we've got some minor loss carryforwards available to us in certain entities. So for 2014, it's obviously going to be a lot dependent on how well the business does and how much capital expenditures we're able to put through. But a rough estimate is probably in the, say, $125 million mark, plus or minus $25 million.

Operator

Your next question comes from the line of Robert Kwan from RBC Capital Markets.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Just -- you mentioned the volumes on ethane and butane. Just wondering with the propane volumes and specifically where inventories sit versus where they were a year ago, did we see accelerated volumes in Q4? Or are you basically sitting where you were year-over-year and therefore set up for similar volumes into Q1?

Michael H. Dilger

I think our inventories are slightly lower than they were a year ago. But we're sensing winter is coming to an end despite the weather outside today. And again, we're forecasting normal weather and normal patterns for the balance of the year.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. If I can, I guess, come back and kind of reposition an earlier question in terms of some of the constraints in moving. Enbridge has talked a little bit about optimizing the mainline system. Just wondering if you have any early indications how that would impact [ph] your access for NGL mix into that system and onwards into Sarnia?

Michael H. Dilger

I'm not aware. I'd say Pembina's not aware of any implications of that on us.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And then just the last question [indiscernible] is around the rail business. And I guess the same thing as it relates to the other NGL products with respect to new tank car regulations. Just any thoughts on how that either impacts or doesn't impact you. And if there are modifications that you need to make under your lease agreements, are you on the hook for those costs?

Michael H. Dilger

Well, first of all, in terms of the rail cars, and I don't remember what they called the rail cars that were mentioned as a concern, but I learned in the last week that that's -- only about 6% of our fleet are those kinds of rail cars. And the rail cars we have of that type are less than 5 years old. And as you know, Robert, we lease our rail cars. And so we will be striving to flip those cars into the newer designs. So it's not really a material concern of ours.

Robert Kwan - RBC Capital Markets, LLC, Research Division

Okay. And are those kind of ratably over the lease? Or do you have the ability to turn those back pretty quick?

Michael H. Dilger

I don't have that detail, but I'll endeavour to get it by the Investor Day.

Operator

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

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Would you please be able to comment further on your full-service terminal build-outs and how you evaluate the economics of those sites?

Michael H. Dilger

We were a little disappointed in 2013 with the number we had done. We hope to keep ramping that activity up, either 100% Pembina or in partnerships. In terms of economics, those terminals don't have long-term take-or-pay type contracts, Steven. So we're targeting significantly higher returns and -- on other businesses. It wouldn't be unusual to target a 20% to 30% rate of return on those because as you know, it's -- there's no guarantees in that business. You take operating cost risks. You take volume risk. So it's all about high-quality service and being in a great location. And we certainly are targeting sites that have those characteristics.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

Do you look at revenue per site and maximize -- how to maximize that?

Michael H. Dilger

Absolutely.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

And then the -- and they generate throughput for the pipeline since always the idea they're always near a Pembina Pipeline?

Michael H. Dilger

Exclusively. I mean, those are destination locations. And we got into that business to vertically integrate it to attract volumes to our system. If you go back 3 or 4 years, we actually had trucks coming from our core areas, driving by our systems and going to competitors' pipeline system because we couldn't offer the service. And so we are building those out to attract incremental volumes. As we do with our Gas Services business and our other businesses in the field is really to become our own customer and increase throughputs on our core systems.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

There's been some discussion that a new gas plant might get built in Northwest Alberta. Is Pembina involved in any way in looking at building new gas plants?

Michael H. Dilger

Always. We have -- you wouldn't believe the opportunity set that's in front of us right now in terms of constructing shallow and deep cuts. It's unbelievable. There's always competition in that business, so who knows how we'll end up. But we -- I think our -- as I said previously, maybe -- and we're very fortunate. It's not always like that, and it certainly has not been like that. But it -- we have to make some hard decisions on which projects we can do because we can't do them all. And so we're going to choose the ones like with the full-service terminal switch, we think can best capture long-life hydrocarbon reserves to our value chain.

Steven I. Paget - FirstEnergy Capital Corp., Research Division

And how do you look at those? Do you contract them enough to make your capital back and so on? Or do you contract them even more than that to generate the returns?

Michael H. Dilger

I think the past is indicative of the future. You look at Resthaven, 15-year take-or-pay contracts; Saturn, 10-year take-or-pay contracts. And so you could look at that model and work. There'll be no reason to have any less -- any lower level of contractual certainty than we have in the past.

Operator

Your next question comes from the line of Matthew Akman from Scotiabank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Just wondering what the remaining kind of regulatory and environmental approval hurdles are on starting construction with the Phase 2 pipeline expansions.

Michael H. Dilger

Phase 2? I think we're a go. Is that right, Scott?

J. Scott Burrows

We expect the LVP Phase 2 to be in April of this year, and then the regulatory approval for HVP Phase 2 is expected more in the fall of this year. And Matthew, there's really nothing, just normal course.

Michael H. Dilger

Yes. I'm not that focused on that because those are really just pump station additions. So most of those pumps are on existing sites. And so it's not like Phase 3 or a pipeline project where you have linear disturbances that affect lots of landowners and communities.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Okay. And then as far as the integrity spending program on the Conventional Pipelines goes, I guess you guys are probably almost a couple of years into an increased integrity spending phase. I'm just wondering if you can update us on how that's gone, whether there's been any surprises and whether you think that the higher level of integrity spending will extend out further. Or will it start to taper off in the next couple of years?

Michael H. Dilger

On average, we spent as much as we expected. There are always things that are worse than you expected and things that are not as bad. But on average, we had a program that we've been ramping up, actually, since Al Charlesworth joined us a number of years ago. But I think we're at or near peak spending on that or in weather events and things like I mentioned earlier. And we hope that those will start to taper off over the years. I mean, we're ready now, as I said, for Phase I and Phase 2, and our future expansions for Peace are brand-new pipe. And so it stands to reason that those should start to decline in the coming years.

Operator

And your last question comes from the line of David McColl from Morningstar.

David McColl - Morningstar Inc., Research Division

I just want to jump back to Cornerstone Pipeline a little bit. You mentioned the cost increase there. I'm wondering if you can break it down a little bit more into how much was associated to labor inflation? How much was a scope issue? And what I'm really trying to get at here is understanding whether you feel any of your other kind of growth projects in Alberta could be exposed to cost creep due to labor inflation or if you start to take steps to maybe lock in the rates with contractors?

Michael H. Dilger

All our -- all of our projects are subject to labor inflation. If you do the math on Cornerstone, it's 4% to 5% a year. And if, hypothetically, that project didn't get sanctioned this year, and it came on a year later, you can see adding 4% to 5% is our crystal ball. So if it comes on in 2017, it's going to be inflated over that timeframe. If it comes on in 2018, it will be inflated over that timeframe. In terms of Peace, we use those similar Peace Phase 3. That's what we're carrying in our cost estimates there with Saturn with any of our gas processing plants. Those are not bad numbers for us. Things can happen in any given timeframe. Those can go up or go down, but we generally use about 5% on total project cost.

Operator

And this concludes our question-and-answer session. I'd like to turn the call back over to our presenters.

Michael H. Dilger

Well, thanks, everybody. I'd just like to take the opportunity to thank all the Pembina employees who work so hard in 2013 to create this terrific year and the support of our shareholders. We had a great ride together from -- if you think about when we started Provident -- acquired Provident, and we had that tough second quarter. We've had a great, great ride up to, I guess, we're over $40 right now. So that's great news. And then finally, thanks to all the stakeholders in that community for the support. And with that, we will sign off. So thank you, everyone.

Operator

And this concludes today's conference call. You may now disconnect.

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