Pembina Pipeline Corporation (PBA) Q4 2014 Earnings Report, Transcript and Summary

Good morning. My name is Kurt, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation fourth-quarter and annual results conference call. [Operator Instructions] Mr. Scott Burrows, you may begin your conference.

Thank you, Kurt. Good morning, everyone and welcome to Pembina's conference call and webcast to review our fourth-quarter and annual 2014 results. I'm Scott Burrows, Pembina's Vice President, Finance and Chief Financial Officer. Joining me today is Mick Dilger, Pembina's President and Chief Executive Offer. For this morning's call, I'll start by providing a high-level review of our financial results, and remind everyone to please visit Pembina's website for our full annual and quarterly financial results, which we released yesterday after markets closed. Mick will then provide an update on Pembina's growth projects. Before closing remarks and Q&A, I will discuss our recent financings and financial position. I would 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. Further, 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 the Company's various financial reports which, are available at Pembina.com and on both SEDAR and EDGAR. Actual results may differ materially from the forward-looking statements we express or imply today. I'm happy to report that Pembina finished off 2014 as another record year. In fact, it was the most successful year in our Company's history on almost all fronts. Our record results were driven by strong operational performance, which allowed us to achieve operating margin of just over CAD1 billion, an increase of almost 14% over 2013. We grew our cash flow from operating activities by almost 17% to CAD800 million, and 10% to CAD2.45 on a per share basis. EBITDA also increased by approximately 11% to CAD920 million compared to last year. I'd encourage listeners to review the news releases, MD&A, and financials we issued yesterday, which provide their full results on a fourth-quarter and year-end December 31, 2014, as I won't go over each financial metric on today's call. This will allow us to move more quickly into the question-and-answer period. That said, I'd like to provide some additional color on the impact of commodity prices on our business during the latter part of the year. Despite the success we achieved during 2014, there's no disagreeing the decline in commodity price had an impact on our results in the fourth quarter, which ultimately offset some of our strong full-year results. The impact of the market decline was seen most as relates to our midstream business, and resulted in Pembina recording an inventory write-down of CAD38 million to reflect lower inventory carrying costs. To put commodity prices into context, the average realized sales price in the fourth quarter on a Canadian dollar per barrel basis for propane decreased about 33% at Redwater West, and 27% at Empress East, compared to the fourth quarter of 2013. Average realized sales prices for butane also decreased almost 24% at Redwater and 26% at Empress. Of the CAD38 million write-down, approximately CAD5 million was related to our crude oil and condensate products, which were protected through hedges and will be recovered in the first quarter of 2015. Looking ahead, we are starting to see a modest recovery in propane prices and, to a lesser extent, butane prices. Pembina plans to stay the course. And we remain confident that current market conditions will not interfere with our medium-term goal of adding approximately CAD700 million to CAD1 billion of EBITDA, which could essentially double our EBITDA by 2018 as we bring our CAD5.8 billion portfolio of fee-for-service projects on-stream. Before turning the call over to Mick, I'll quickly highlight a few operational achievements during the year that led to our record annual results. We are very pleased to report all-time highs for throughput in both our conventional pipelines and our gas services business during the year. In conventional pipelines, throughput was up 17% year over year 2014, and for the fourth quarter, volumes averaged a record 612,000 barrels per day. Which, represents an increase of approximately 22%, compared to the same period of 2013. As of December, monthly average throughput reached the highest levels we have ever seen, at 631,000 barrels per day. Our Phase I expansions, which were placed into service in December, 2013, higher truck terminal volumes, and additional throughput from new connections and assets, were the main drivers of the record volumes. In the last few months of the year, we also saw a bump in throughput due to volume shift on the Vantage pipeline, which closed on October 24, 2014. We expect to see volumes further increase this year as we bring our Phase II crude oil condensate and NGL expansions online, that Mick will talk about momentarily, as well as a full year of contribution from the Vantage pipeline. These factors contributed to operating margin of CAD302 million in 2014, 20% higher than CAD251 million recorded in 2013. Gas services also realized higher throughput. With average processing volumes increasing by over 61% for 2014 compared to last year, and 47% during the fourth quarter, compared to the same quarter of 2013. Volumes were boosted because of our Saturn I facility, which came onstream in late October 2013, and which operated above its nameplate capacity of 200 million cubic feet per day during a large portion of 2014; improved performance at our Cutbank Complex; and new volumes from the Resthaven Facility, which was placed into service in early October 2014. This strong performance led to a 37% increase in operating margin, which came in at CAD107 million for the year compared to CAD78 million in 2013. In the midstream business, full-year operating margin was CAD528 million, and improved over the CAD486 million realized in 2013 due to increased storage opportunities in the first half of the year, along with higher throughput volumes, wider margins, and strong NGL and propane prices early in 2014, predominately at Empress East and offset by reduced commodity prices in the fourth quarter, as I have previously discussed. And last, in our oil sands and heavy oil business, we saw steady performance as is expected, with operating margin coming in slightly higher on an annual basis at CAD136 million due to additional interruptible volumes on our Nipisi Pipeline and fees from a new connection. On the whole, I am very pleased with the results we've achieved in 2014. I will now pass the call over to Mick, who will give an update on how our growth projects are progressing.

Thanks, Scott, and good morning, everyone. Further to what Scott mentioned, 2014 was a really exciting year for Pembina. We set financial and operational all-time highs. We had outstanding safety record with no employee incidents throughout 2014; progressed our CAD5.8 billion of committed capital growth projects; placed almost CAD900 million of new assets into service; completed the Vantage acquisition and subsequent expansion; signed additional contracts for Phase III Peace Pipeline expansion; announced approximately CAD1.4 billion of new projects; raised CAD1.1 billion in new financing; and increased the common share dividends. I'd like to thank all of our staff and contractors for working so diligently over 2014 to achieve such impressive results. One of the most exciting developments during the year was our entrance into North Dakota and Saskatchewan Bakken play. We were very pleased to close the acquisition of Vantage Pipeline and associated assets in October, 2014. Subsequent to the year end, on February 10, 2015, Pembina announced that we entered into agreements to expand the Vantage Pipeline system for an estimated capital cost of CAD85 million. For the project, we will be increasing Vantage mainline capacity from 40,000 barrels per day to approximately 68,000 barrels per day through the addition of pump stations and the construction of a new gathering lateral. The Vantage Expansion is supported by a long-term fee-for-service agreement with a substantial take-or-pay component, and the gathering lateral is underpinned by a fixed return on invested capital agreement. Subject to regulatory and environmental approvals, we expected the expansion to be in service early 2016, and once it is operational, we expect the overall system, including SEEP, to result in an EBITDA range of CAD75 million to CAD110 million per year, with the base of the range representing consolidated take-or-pay volumes. This acquisition overall will contribute to a meaningful increase of about 10% in EBITDA. Another exciting development is our Phase III Expansion plan, which continued to grow through the latter part of 2014. Recent project highlights include the announcement in September that we plan to put two new pipelines in the ground in the Fox Creek to Namao Corridor, versus one, as originally contemplated. We expect these pipelines to have an initial capacity of 420,000 barrels per day, and an ultimate capacity of over 690,000 barrels per day, which could bring our total capacity between Fox Creek and Namao to an excess of 1 million barrels per day. We submitted our regulatory application for these pipelines on September 2, 2014. We also announced another segment associated with this project – a new pipeline spanning 70 kilometres between Wapiti and Kakwa, which will feed into downstream expansions. The additions are expected to bring total project spending to over CAD2.4 billion. Our in-service date remains in late 2016 to mid-2017 timeframe, depending on the regulatory timing. Volume commitments for the project continue to ramp up. On September 10, 2014, we announced that we have Phase III volume commitments for 289,000 barrels per day, and by September 22, 2014, we announced additional agreements, bringing total volume under contract to 307,000 barrels per day. Since then, we have received an additional 55,000 barrels per day of secured volumes, despite challenging markets near the end of 2014. Total committed volume is now 362,000 barrels per day, or 86% of initialed, or 120,000 barrel per day capacity. With our expansions underpinned by contracts, we turned our efforts to further securing the majority of existing crude and condensate volumes on our Peace and Northern systems under long-term, fee-for-service contracts. In aggregate, Pembina now has approximately 690,000 barrels per day under contract. Once the Phase III expansion is brought into service, virtually all of the throughput on Peace and Northern systems will be under long-term, fee-for-service contracts. In the immediate future, were focused on bringing our Phase II Expansions online. For the crude oil and condensate portion, the project is slightly delayed by a matter of a few weeks. We expect to be mechanically complete in April 2015, and commissioned in the second quarter of 2015. Subject to regulatory approval, the NGL component of the project should be in service in the third quarter of 2015. Overall, the Phase II Expansions are continuing to track on budget. Our pipeline lateral program to aggregate new volumes onto our system is also moving along well. We expect our Willesden Green pipeline lateral to be in service in mid-2015, and, subject to regulatory and environmental approvals, we anticipate our Edson pipeline laterals to be in service in mid-2016. We have also started work on our previously announced Northeast BC Expansion, a CAD220 million expansion in Northeast British Columbia, which will transport condensate and NGL for various producers in the liquids-rich Montney resource play. This project, which parallels our existing infrastructure in the area, is expected to have a base capacity of up to 75,000 barrels per day. A long-term cost-of-service agreement is underpinning the Northeast BC expansion, and subject to regulatory and environmental approvals, we expect to be in service in late 2017. Now onto gas services. In October 2014, our Resthaven Facility was successfully commissioned and placed into service on October 10. We announced that we are planning a CAD170 million gross cost expansion of 100 million cubic feet per day to the Resthaven Facility, which includes a construction of a new gas pipeline. This expansion is underpinned by a long-term fee-for-service agreement. Pembina expects to work on the plant to be completed mid-2016 and the gathering pipeline to be in service mid-2015. On November 27, 2014, Pembina announced plans to construct a new 100 million cubic feet per day shallow cut facility called Musreau III for an estimated cost of CAD105 million, which is supported by a long-term agreement. The plant will leverage the engineering design and execution strategy of our Musreau and Musreau II facilities. I'm also very pleased to report our Musreau II facility was placed into service on December 17 and came in on budget ahead of schedule by one quarter. Construction is also progressing at the Saturn II and SEEP gas plants, and both projects are tracking on schedule and on budget. Once these facilities come on stream, we expect our total processing capacity to reach 1.5 billion cubic feet per day, including ethane-plus extraction capacity of 870 million cubic feet per day. Now on to midstream. At our Redwater site, over 80% of the equipment has been set for RFS II, and module fabrication is substantially complete. The project is tracking on schedule with construction currently 65% complete. For RFS III, detailed engineering work is underway, and over 30% of long lead equipment has been ordered. We have received regulatory approval and have submitted the environmental application, which we anticipate to receive later this year. Pending environmental approval, we expect RFS III to be in service in the third quarter of 2017. In the fall of 2014, we announced plans related to 2 longer-term development opportunities: the site selection for our proposed propane export terminal in Portland, Oregon; and the creation of a new diluent hub in Alberta's heartland. For our proposed West Coast propane export terminal, Pembina's dedicated project team is continuing to make progress with community, regulatory, and special interest group engagement, and has also advanced detailed engineering design work in advance of a number of permit applications to be submitted throughout 2015. For the Canadian Diluent Hub, or CDH, site preparation began in late 2013 and is ongoing. We plan to phase in pipeline connections and storage once we receive further regulatory and environmental approvals, and we expect CDH to reach full service by mid 2017. All in all, we're very pleased with the project we're making on executing our growth plans. Scott?

Thanks, Mick. During 2014 Pembina had 3 successful financings. We completed 2 preferred share offerings, one in January and another in September; both for gross proceeds of CAD250 million. In April, we also announced CAD600 million in 30-year notes, and issued 5.6 million shares to fund a portion of the Vantage acquisition in October. More recently, in January 2015, we issued CAD450 million of 10-year notes and CAD150 million of 30-year notes. As of February 20, 2015 our CAD1.5 billion credit facility was substantially undrawn. Between Pembina's clean balance sheet, undrawn credit facility, and proven access to the capital markets, I'm confident Pembina's financial flexibility and our ability to fund our CAD1.9 billion capital program.

Thanks, Scott. In summary, 2014 has been a great year for us. We continue to do the important things right – operating safely and reliably, de-risking our existing business, securing additional Phase III volumes, and positioning ourselves to generate long-term shareholder value. Not only did Pembina break financial records in 2014, we did this while also having a full year of zero lost-time injuries and zero recordable employee injuries, despite employees having worked 24% more hours than in 2013. Maintaining safe and reliable operations is of the utmost importance to our Company. So, I want to commend all of Pembina employees for achieving this best-in-class safety result. Doing the important things right will continue to be our focus as we progress through 2015. While we are facing some commodity headwinds, I'm confident that this will not impede our medium-term goal of essentially doubling our EBITDA by between CAD700 million and CAD1 billion in 2018, as we continue our strategy of pursuing low risk contracted projects to outgrow the component of our overall business that is directly related to commodity prices. I believe very strongly in Pembina's future, and we plan to do what's required to achieve our goals of continuing to drive long-term shareholder value for our loyal shareholders for many years to come. Okay. I'd like to remind listeners that we are hosting our Investor Day on March 10, 2015. The presentation will be webcast and available through our website under Investors Center; Presentations and Events. For those of you who be attending the live presentation, we look forward to seeing you there. With that, we'll wrap things up. Operator, please go ahead and open up the line for questions.

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

Thank you. Good morning.

Morning

We are now two-thirds into Q1. I'm wondering if you could just give us a sense of what you're seeing in marketing in terms of realized prices, spot prices, how hedges are mitigating the effect of commodity prices that to us appear to be weaker than they were even in Q4?

Yes, I mean, Linda, we don't give specific guidance. And, quite frankly, we're – for us we only have our January financial results so far. I think for us they're tracking where we thought they would be late in December, early January. In terms of the question around hedging. We will be recovering approximately CAD5 million to CAD7 million on the crude oil and condensate side. As we mentioned in the conference call. Part of the inventory write-down was on the crude oil and condensate. And, that was really a timing issue. It was a December transaction that settled in January. So, we did have hedges to offset that. Which, will be realized in turn – in Q1. For the other commodities we do have some small amounts of butane and propane hedge. But it's nothing overly material. And, from our perspective, what we've seen in February is pricing that was above January and even above December, for that matter.

So generally, it's what Scott said. We don't really have actuals beyond January, but it's feeling better than it did in December.

Okay. And, pricing discovery can be little bit more challenging for us in Redwater West. Can you comment on your spot prices that you're seeing there? If – or, maybe we could take that offline?

Well, I mean, you can pull it up on Bloomberg. And, roughly, the spot pricing in Bloomberg is anywhere from CAD0.33 or CAD0.37 a gallon for propane.

At Redwater West?

Yes.

Okay. And, just a follow up question. Can you give us any sense of, maybe, any operating stats that could be available beyond NGL sales volume in terms of contract mix or anything like that?

You mean percentage of fee-based versus not fee-based, or?

Anything, yes.

Yes, the fee – the NGL portion of the Business is between CAD110 million and CAD120 million a year. Keep in mind, that's going to go up substantially in 2016 when RFS II comes online.

Thank you.

Thanks, Linda.

Your next question comes from the line of Robert Hope from Macquarie Capital Markets. Your line is open.

Thank you. Maybe just one quick follow up on that. With the pricing that you've seen in Q4 and Q1 has that altered how you're looking at hedging, potentially, your propane and butane moving forward? Will you look to add more hedges? Or, will you just let that exposure decline on a percentage basis as your other businesses grow?

Well, for sure, the latter. I mean, we're going to – clearly, we're diversifying out of commodity exposed. And, we are always looking for ways to swap a commodity-exposed business for a fee business when it makes economic sense. So, generally, we keep our eyes open for that. In terms of the hedging practice we have. We're continuing right now with the current hedging practice. However, we are underway with a review of whether we should hedge more than we have been hedging. Clearly this time – at the bottom of the cycle is maybe not the best time to decide that. So – but, we're investigating it.

All right. Thank you for the color. And, maybe just one follow-up. I'm just wondering. When we look out to some of your longer dated projects. Have there been discussions with your committed shippers regarding potentially pushing out the timing. Or, altering flame commitments at this point?

None whatsoever.

Good to know. Thank you.

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

Thank you. Good morning, everybody. And, great to hear the backlog, kind of, continues to go so smoothly. One question I know you guys have gotten over the last few months. But, just to, kind of, keep our finger on the pulse. There haven't been any substantive discussions, if you will, of producers coming to ask you to re-price midstream services, have there? Or, maybe, I should we re-ask. As far as, that would change any net present value of any contracts?

Only upwards.

Only upwards. Excellent.

I mean, we keep signing people up. And, we do get that question a lot. But we – I think, I'm not saying those questions would never come. But, remember this is a 2017 project. And so, people are focused more on the near-term. But, we have committed contracts. We have to build it. They have to pay. And so, there's really not a lot of room for discussion other than a scenario where it would be mutually beneficial.

Appreciate that. Actually, maybe a micro question on just the Phase III contracted level. At 86% here, is the ultimate target to get to 100%? Or, for operational reasons you can't really contract greater than 90% for instance? So, you're effectively there?

Well, our objective is to start to access the very accretive expansion. So, we can go to 690,000 from our current levels for 420,000, by adding pumps. And, but, the cost of adding those pumps is only a small fraction per barrel of the pipeline looping projects. So, we have a long way to go in terms of getting to 100%. But, to answer the rest of your question, we could easily sign up 100%. But, we do want to keep some available for interruptible shippers. So, we wouldn't contract the whole pipeline 100% under 10-year take-or-pays. We'd probably stop short of that.

Okay, that's helpful color. And then last question, if I could. Just really from, I guess perhaps, the all in expense line for fourth quarter. Normally, fourth quarter sees a seasonal uptick. In this case we've seen it 17% up, both sequentially and year over year. Is this level representative of a new baseline of O&M expense? Or, should we see that tick back down, say, for instance, for the first part of 2015?

I can't answer that question that granularly. But, our G&A and our operating costs per barrel over time as we grow, I perceive it will be flat or decreasing per barrel, just because of economies of scale.

Okay.

Yes, I think, Carl, you mean, keep in mind that 2015 will have a full year of Resthaven. We'll have a full year of the Vantage pipeline. We'll have our Phase II costs. We'll have Saturn II costs. So, OpEx overall will go up just by the nature of increased assets coming into service. And, in terms of Q4, there was some slightly higher cost. Again, that was mainly new assets. Conventional was up slightly. A large portion of the conventional increase was due to the Western system. And, if you recall, that's a cost of service type pipeline. So, those OpEx will be recovered through revenues. And, we had a one-time slope replacement on one of our pipelines. But, if you remove those, kind of, one-time items Q4 was generally in line.

Excellent. I appreciate the color, Scott. Thanks, guys.

Thank you.

Your next question comes from the line of Robert Catellier from GMP Securities. Your line is open.

Good morning and congratulations on the zero loss time injuries

Thank you very much.

I just want to follow up a little bit on the hedging. You talked, it seemed – you gave your comments there. It seemed directed towards NGL marketing. But, I've asked the question on the frac spread. Any intention to maybe look at changing your hedging strategy there?

We're looking at all possibilities. Right now, what we do is we hedge half the input cost of gas. And, we do that by selling pro – or, butane and condensate, because they're both ratably acquirable and sellable. And, there's a good liquid market for it. When we think about propane, because we store propane. And, there isn't a good hedge market in Edmonton or Sarnia. We choose to stay long on propane. We – in the past, the Company has put in places, US-based hedges and then – but, then you still have a basis differential open. So, it's not perfect. But, we are looking at those possibilities.

Yes, I think we're looking at considering both hedging the NGL barrel. As well as potentially putting on protective measures around inventory as well.

Okay. And, when you look at the outcoming NGL year. Does the current price environment give you an ability to re-contract with terms that, maybe, transfer a little bit of the price risk to the shippers? To the producers?

Well, the product we own at Taylor or at Empress. The short answer is; in the short term, no. In the longer-term, possibly. But, for the – keep in mind, a lot of the propane we market as agent for others. And, so they're already getting the full impact of the change of commodity prices. That doesn't stick to us at all. And if you go forward, keep in mind Redwater II and Redwater II, notwithstanding, we're marketing that propane. We are doing it as agents. So, it's – there's no commodity exposure on any of those volumes.

Okay. Thank you. That's helpful. Just, a couple more quick ones here. Scott, or maybe, Mick. I wonder if you're seeing the engineering construction cost environment improving?

We – yes, we are. It's going to take a little bit of time. Because there's a backlog of projects underway. Whether it's on shop floors or engineering firms. But, we are aspiring to cut, up to, let's say, 5% of our G&A, our OpEx and our capital project costs over the spend profile. Which, let's just use rough numbers. We have CAD4 billion, CAD4.5 billion of remaining projects, and we can save 5%. That's actually a much larger number than what propane just changed. So, there is a silver lining in this environment for us to take advantage of really lower costs across the board. So, that's a high focus area for us right now.

So, nothing you've seen to detract you from obtaining that goal of the 5% improvement?

It's early days, but that's what we're – what our objective is.

Okay. Then finally on the propane export terminal. I wondered if – I'm sure shippers to some extent are distracted by other issues. But, what progress you've made in being able to come to – drumming up customer demand there? I would think, at least in part, what's happened with the commodity price environment would put a focus on any way to get improved net back. So, I'm wondering if you've drummed up more interest on the Portland export terminal?

Well, I think it's useful for you to understand that we have all of the propane we need to fill the terminal as contemplated. Already. So, that's all committed. Propane. Some of it's our own. A lot of it belongs to our producers. And so, we don't need any more customers, or we just have to work our way through the approval process.

Right. So, that's all. You have all the fee-for-service business or commitments or indications that you need for that project?

Correct.

Okay. Thank you.

You're welcome.

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

Thank you and good morning. First question is on long-term propane. For the last five years, the Edmonton to Sarnia propane price differential has been trending upward as Western Canadian production increases and other midstream companies take transportation offline. Do you see this trend reversing, as rail propane transport options come into play?

It's really tough for us.

Let me, I'm going – Steven, I think there's 2 dynamics there. And, we don't necessarily always think about it from an Edmonton to Sarnia market. We really think about it as an Edmonton to Conway.

Yes.

And, to your question. There's no doubt that those differentials have widened. Due to increased supply in Canada. As well as the Cochin Pipeline reversing. In the immediate term, we don't see that necessarily reversing. Because, we are now having to move more propane by rail. In terms of the Sarnia differential. Again, that's usually a differential off of Mont Belvieu. And, we have in the short term, seen that compress slightly as well. We're not going to gaze into our crystal ball and guess what that is for 5 years out. But, in the short term we have seen that pricing come down a little bit.

We don't have a crystal ball.

Well, thank you. My next question is on LNG. If an LNG export terminal is built. And, gas starts being shipped West. Is there an opportunity to take the liquids out of that gas before it goes to the West Coast?

I think the answer is yes. That's really what our Northeast BC expansion is going to do. I mean it's a pre-build for that eventuality.

Well, will that pipeline be connected to a Pembina gas plant or one of the producers gas plants?

Hopefully both. But, right now just producers.

Thank you. Those my questions.

Have a good one.

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

Good morning. Just with the lower commodity prices. That obviously puts pressure on cash flow heading into 2015. I'm just wondering. You've got good liquidity. But, does this change how you think about your funding? And specifically, any potential equity needs? In terms of managing the credit metrics and whether rating agencies might be giving you a pass during the construction?

Yes. So, in terms of the rating agencies, DBR – sorry, S&P reconfirmed our rating a week-and-a-half ago, 2 weeks ago, at triple B. So, they're well aware of the plans. In terms of the funding, nothing's changed from our stated 50/50 debt equity. So, that's how we're going to lay out the plan. The funding is, depending how much capital we spend in the year. How much cash flow we generate after dividends. So, we're a little early in the year to talk about that, Robert. But, given, the kind of, the capital program we've laid out and the timelines we've put out there, and the 50/50 debt equity. A lot of that's going to come down to how much cash flow the Company can generate in 2015 and 2016.

Okay. That sounds like, Scott, that's fair to say, you're not sounding particularly concerned. That, where there may have been any need for equity in future years. It doesn't sound like, right now, you're thinking about accelerating that into 2015?

I, well, there's certainly, if you look out over the next 3 years, there will be likely a requirement for a small amount of equity. The timing of that will really depend on, like I said, the timing of the CapEx program. If we add any new capital projects. For example, 2015 we're already up from CAD1.9 billion to, maybe, closer to CAD2 billion because of the Vantage Expansion and a few other small things. And then, it becomes a function of, will we get through the entire CAD2 billion capital program this year? Or, will some of it slip into 2016? A lot of that depends, too, on regulatory approvals. So, once we get regulatory approvals for some of our projects, we can order long lead equipment. So, there's a lot of timing that goes into it. I think when you run the math, it's clear we'll need a small wedge of equity sometime between now and 2017. It's just a little early in the year to discuss specific timing on that.

Fair enough. You referenced the potential, the – if you add capital to the plan that could change things. How are you thinking about that, right now, given there was downward pressure on FFO? Like, are you changing, kind of, the hurdle rates and looking at things that are either the most strategic things you need? Or, are you just, kind of, taking the view that you're not particularly capital constrained? You've got good liquidity. So, if you find something you think is accretive, you're just going to go ahead and do it?

Robert, we, I – the answer to your questions is, we're always looking for that. Those opportunities. We haven't really raised our hurdle rates or become concerned on capital. I mean, we just had a great record pricing on our debt issue. So, I think the markets – and, I think it was well oversubscribed. So, the market is – it seems to be strong for us. In terms of overall opportunities. There's still lots of greenfield interest that we're responding to. And clearly, more opportunity to acquire loose assets in a very weak market than a strong market.

That's great color. Just, maybe, last question here. With the new Phase III volumes here. Can you give a sense as to where these volumes are entering the system? And, when transportation might be commencing?

Yes, I would say they're our traditional basins. So, it's Montney, Deep Basin, and Duvernay. And, in terms of when they start up. We'll start up in mid 2017 and then wrapping up through to mid 2018.

Okay. Is it roughly equally split amongst how these new volumes are entering the system, i.e., is it proportionate, kind of, EBITDA generation or is there more of either a longer or shorter run?

No, I'd say it's in the middle.

Okay. That's great. Thank you.

Your next question comes from the line of Dirk Lever from AltaCorp Capital. Your line is open.

Thank you very much. Congratulations to you on the past year and may you have continued good fortune as you move forward here.

Thank you.

I wanted to get a little bit of clarification. I was scribbling down notes when you answered Linda's question. And, you had talked about NGL. You said CAD100 million to CAD110 million. Is that a quarterly-based figure that you're looking at? Or, is that an annual number? I'm sorry about that, to ask you again.

No, that's our annual fee-for-service revenue that comes from our –

Got you.

From our NGL portion of the Business.

Thank you. I needed that. The other question. I've got 2 other ones for you. When you're looking at your income taxes rolling forward. If you've got some shield coming from completed projects that we should be thinking about cash taxes differently this year?

I think, right now, you can think about them roughly flat as 2014.

Okay. And then, you'd talked about how construction – the engineering, et cetera. You're seeing some easing on pressure. But, a lot of the costs are to do with steel. So, how should we looking at your capital costs when a lot of these costs are on the steel side? I'm thinking about the U.S. dollar having moved?

Yes, both good observations. A fair amount of our tangibles for Redwater II and Redwater III, we've already bought. But, we're not going to see big savings there. Steel generally is weaker. The U.S. dollar is stronger. But, where we really see the savings is in construction costs. We're – there's just a lot more, or, a lot less competition for construction services in the coming years. You think about the producers' reductions in capital. So, if we as an example, want to set up a camp. That's a lot easier when producers are slashing their capital budget by billions of dollars. So, it's more, not on the tangibles. But, it's on the intangibles that go into constructing a pipeline. Which, are generally in excess of 50% of the total cost.

Okay, so there's a bit of an offset then?

Yes.

Thank you very much.

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

Hi, good morning.

Morning.

I wanted to ask a couple of questions on capital allocation. And, obviously the different commodity environment we're in. My first question is whether there's any discretionary capital? Let's say, capital that you plan to spend this year that might not have been fully contracted? Such as, around terminals, that you might consider deferring into 2016 or beyond?

Not at this time. In terms of our strategy and our project pipeline. Whether con – truthfully, whether the price of oil and associated products was CAD50 or CAD150, we'd be doing the same things. I think, in this environment, the difference is we think we can do – implement our project pipeline, maybe, a little more cheaply than we thought we could previously.

And Mick, is there any type of, or line of business, or type of investment, that you're more attracted to, now. Or, less attracted to, given the change in commodity price? And in the event it lasts longer, I'm thinking, for example, the Vantage Pipeline investment. Which, is a little bit outside of the normal sphere for Pembina. Is there any strategic change on capital allocation in terms of types of assets that you'd be more interested in now?

I wouldn't say related to specific geography the way you've described. But, we're obviously thrilled with Vantage. If you do the multiple analysis, inclusive of the expansion. And, assuming that it's almost full. I mean, it's been a wonderful acquisition for us. So, more fee-for-service assets. And, usually adjacent or connecting, to our infrastructure. And, or, in terms of the overall value chain. A step upstream or downstream of that is typically what you've seen from us over the last 10 years. And so, our strategy remains intact.

And last question related to this is, I mean, you guys have a premium organic growth as laid in front of you. You don't need to do acquisitions. But, I think you mentioned, maybe, that acquisitions are a little more attractive now than they would have been. Is that rising in your priority list?

Yes it is. I mean we – we're not sure we can – were there to be an acquisition. We're not sure we can buy something cheaper than we have in the past. I don't know that the market's come that far yet. Maybe it will, if this environment lasts for a long time. But, we don't have that sense today. But, what we do have a sense of is there's going to be a lot more deals closed. Some producers, for example, that would have never considered monetizing a gas plant. Or, something like that. May just want to do that in this market. So, we're just seeing a lot more opportunity. I don't know that it'll be less expensive. Interest rates are going down. Costs of capital, in our Business, aren't really going up. And so, it's just too early to see whether we can buy cheap.

Probably just wait a few more months?

Maybe.

I'm just – thank you. Those are my questions.

Thank you.

The next question comes from the line of Steven Paget of FirstEnergy Capital. Your line is open.

Well, thank you. How is the fact that Western Canada is basically full on ethane, affecting the market for extraction services in the province? In contrast to the proposition of extracting them downstream?

Steven, the incremental – there doesn't seem to be incremental ethane demand at this time.

Yes.

And so, you know, for example, with Redwater III, we didn't put in at the last hour to take out ethane.

Yes.

We're positioning our Business to add that capability in the future. But, with commodity prices the way they are, only the highest value products are worthy of extraction right now. And so, generally we're seeing an industry move away from ethane-plus, to a more dew point plants or minus-40 type plants. They're not quite as hungry for the NGLs. What could be the foreseeable future. But, as bases mature and commodity prices get back to normal. Whatever timeframe that might be. We do think that will eventually come as it has over many decades in the past. So, you take your condensate out first and then you go from there as prices permit.

Well, thank you. When I add up your projects that are coming online this year. And, the CAD1.7 billion. And, compare the list of projects from your recent presentation. There's about CAD200 million in smaller projects. Are those mostly related to conventional pipelines in cavern storage?

Yes, as well as potential for some – yes, that's right. Steven, yes.

Well, thank you. As you bring on the next CAD5.7 million in assets, do plan to maintain the same dividend payout ratio?

Well, the ratio has been changing quite a bit with the exchange in commodity prices. So, I don't know which ratio you're referring to necessarily. But, the rough – the math will tell you in your model that we certainly have room to quite dramatically increase our dividend in the coming years. We had a discussion with our Board on that. There's going to be room and it's – I think it's a matter of timing. Keep in mind, that the CAD700 million of incremental EBITDA, that's all long-term, fee-based income. That's kind of our contractual floor. So, even the math on that would indicate we should be – have upward mobility in the dividend. And, if we get anywhere close to full significant upward mobility. So now, it just a matter of us getting comfortable that the projects that we've – we believe are on time and are on budget come in that way. And, as you mentioned, we have CAD1.5 billion. And, if we get – chew through that, I think we're going to be feeling really comfortable about dividend increases in the future.

So, it's, and it's fair to say that the dividend policy is always – has leaned to strong or high dividend payout ratio in the past and probably will in the future?

Yes.

Thank you.

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

Good morning.

Morning.

Just wanted to follow up on the acquisition questions. When you look at the marketplace, do you see any difference or any preference between US versus Canada?

I would say – most of the opportunity that we see, that we're aware of, is in Canada. Because, this is where we live, and it's the basin we know the best.

Yes. A - Mick Dilger That being said, we went into Bakken with Vantage as, kind of, a pilot to get to know that. So, our awareness of that region is increasing quite rapidly. But, beyond that, and beyond of course, Sarnia, Toronto, Central Canada, we have as a Company limited knowledge and henceforth, more nervousness. And, it wouldn't be what Pembina has done traditionally. To step into a new basin. It's just hard to imagine how we would get the same kind of synergy doing that. As, we've seen with our existing strategy. But, as I said, it is early. There could be opportunities that are just too good to pass up in another basin. But, we're not aware of those today.

And then, you did mention producers. And, is it mainly producers that are – you're feeling that the assets are going to come from? Or, is it equally third parties as well?

Anything's possible. But, I think the producers are the ones that were feeling the most need for alternative sources of capital. So, that would be the, prob – in my estimation, the most likely source of assets.

All right. And then, on the propane and ethane. You'd certainly talked a bit about the, it seems like, an oversupply situation in Alberta. Is there a need for a C3 or an EP pipeline out of Canada? Or, is this truly a rail solution?

Pipes are always better, in my opinion, than rail. For many reasons, that are well understood. A pipeline would be great if the economies of scale worked. But, to pipe out of Canada. It's either a really long way to markets in the US. And, if you want to go to the coast, you've got to cross the mountains. And, the cost there is – would generally mean you need 200,000 to 300,000 a day, I'd say, as a minimum to have the economies of scale to do something like that. And, the basin just doesn't have that kind of volume today. But, in the future, if the Montney and Duvernay live up to their potential. There could foreseeably be critical mass to do something like that.

And then, one last question. In terms of the CDH, what sort of demand are you seeing? It's, kind of, been note, there's a concept now for a little while. How's the marketing efforts for attracting volumes to that particular solution going?

They're going well. We have a lot of interest and we're talking to – it's really a matter of downstream connectivity. Where is all the condensate that we're going to have at that site going to go? And, so it's taken a little bit of time. But, it's been well received. And, hopefully we'll be able to say something in the near future.

Thank you very much. Those my questions.

Thanks, David.

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

Well, thanks, everybody. As I said in the scripted statement, we couldn't be more proud of our safety record. I've actually never heard of a company our size having this kind of incident free year. And so again, congratulations to all our staff and thanks for your continued hard work. And, for those on the phone, thanks for your support. So, with that, we'll sign off. Have a nice weekend.

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