Good morning. My name is Kirk, 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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you'd like to ask a question during this time, simply press star then the number one on your telephone keypad. If you'd like to withdraw your question, press the pound key. Thank you. Mr. Scott Burrows, you may begin your conference.
Thank you, Kirk. 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 Officer. 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 in 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 CAD 1 billion, an increase of almost 14% over 2013. We grew our cash flow from operating activities by almost 17% to CAD 800 million and 10% to CAD 2.45 on a per-share basis.
EBITDA also increased by approximately 11% to CAD 920 million compared to last year. I'd encourage listeners to review the news releases, MD&A, and financials we issued yesterday, which provide the full results for the fourth quarter and year-end December 31st, 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 denying 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 it relates to our midstream business and resulted in Pembina recording an inventory write-down of CAD 38 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 CAD 38 million write-down, approximately CAD 5 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 marketing conditions will not interfere with our medium-term goal of adding approximately CAD 700 million-CAD 1 billion of EBITDA, which could essentially double our EBITDA by 2018 as we bring our CAD 5.8 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 were 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 1 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 24th, 2014. We expect to see volumes further increase this year as we bring our Phase 2 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 CAD 302 million in 2014, 20% higher than CAD 251 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 1 facility, which came on stream 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 Cut Bank 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 CAD 107 million for the year compared to CAD 78 million in 2013. In the midstream business, full-year operating margin was CAD 528 million and improved over the CAD 486 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, predominantly at Empress East, and offset by reduced commodity prices in the fourth quarter, as I have previously discussed. 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 CAD 136 million due to additional interruptible volumes on the Nipisi Pipeline and fees from a new connection. On the whole, I'm 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 CAD 5.8 billion of committed capital growth projects, placed almost CAD 900 million of new assets into service, completed the Vantage acquisition and subsequent expansion, signed additional contracts for phase three Peace Pipeline expansion, announced approximately CAD 1.4 billion of new projects, raised CAD 1.1 billion in new financing, and increased the common share dividend. 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 of 2014.
Subsequent to the year-end, on February 10th, 2015, Pembina announced that we entered into agreements to expand the Vantage Pipeline system for an estimated capital cost of CAD 85 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 CEIP, to result in an EBITDA range of CAD 75 million-CAD 110 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 plans, 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 2nd, 2014. We also announced another segment associated with this project, a new pipeline spanning 70 km between Wapiti and Kakwa, which will feed into downstream expansions.
The additions are expected to bring total project spending to over CAD 2.4 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 10th, 2014, we announced that we had Phase III volume commitments for 289,000 barrels per day, and by September 25th, 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 initial 420,000 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 Three 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, we're focused on bringing our Phase Two 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 Two 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. 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 CAD 220 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 on to 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 CAD 170 million gross cost expansion of 100 million cubic feet per day to the Resthaven facility, which includes the construction of a new gas pipeline. This expansion is underpinned by a long-term fee-for-service agreement. Pembina expects work on the plant to be completed in mid-2016 and the gathering pipeline to be in service mid-2015. On November 27th, 2014, Pembina announced plans to construct a new 100 million cubic feet per day shallow cut facility called Musreau 3 for an estimated cost of CAD 105 million, which is supported by a long-term agreement. The plant will leverage the engineering design and execution strategy of our Musreau and Musreau 2 facilities. I'm also very pleased to report our Musreau 2 facility was placed into service on December 17th, and came in on budget ahead of schedule by one quarter.
Construction is also progressing at the Saturn 2 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 2 and module fabrication is substantially complete. The project is tracking on schedule with construction currently 65% complete. For RFS 3, 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 3 to be in service in the third quarter of 2017.
In the fall of 2014, we announced plans related to two 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 progress we're making on executing our growth plans. Scott?
Thanks, Mick. During 2014, Pembina had three successful financings. We completed two preferred share offerings, one in January and another in September, both for gross proceeds of CAD 250 million. In April, we also announced CAD 600 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 CAD 450 million of 10-year notes and CAD 150 million of 30-year notes. As of February 20th, 2015, our CAD 1.5 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 in Pembina's financial flexibility and in our ability to fund our CAD 1.9 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. I want to commend all of Pembina's 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 CAD 700 and CAD 1 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'm going to read. Is this my part at the end here, too? I'd like to remind listeners that we are hosting our Investor Day on March 10th, 2015. The presentation will be webcast and available through our website under Investor Center, Presentations and Events.
For those of you who will 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.
At this time, I would like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad. 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, so 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?
Yeah. I mean, Linda, you know we don't give specific guidance and, quite frankly, 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 CAD 5 million-CAD 7 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 Q1. For the other commodities, we do have some small amounts of butane and propane hedge, but it's nothing overly material.
From our perspective, what we've seen in February is pricing that was above January and even above December, for that matter.
Yeah. Generally, what Scott said, we don't really have actuals beyond January, but it's feeling better than it did in December.
Okay. Pricing discovery can be a little bit more challenging for us in Redwater West. Can you comment on your spot prices that you're seeing there? Or maybe we could take that offline.
Well, you can pull it up on Bloomberg, and roughly, the spot pricing in Bloomberg is anywhere from $0.33-$0.37 a gallon for propane.
At Redwater West.
Yes.
Okay. 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, yeah.
Yeah. The NGL portion of the business is between CAD 110 million and CAD 120 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. 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. 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. 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, at the bottom of the cycle is maybe not the best time to decide that. We're investigating it.
All right. Thank you for the color. Maybe just one follow-up. 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 volume commitments at this point?
None whatsoever.
Good to know. Thank you.
Your next question comes from the line of Carl Kirst from 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 gone 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 reprice midstream services. Maybe I should re-ask as far as that would change any net present value of any contracts?
Only upwards.
Only upwards. Excellent.
We keep signing people up, and we do get that question a lot. I'm not saying those questions would never come. Remember, this is a 2017 project. People are focused more on the near term. We have committed contracts. We have to build it. They have to pay. There's really not a lot of room for discussion other than a scenario where it would be mutually beneficial.
Yeah, I 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. We can go to 690 from our current levels from 420 by adding pumps. The cost of adding those pumps is only a small fraction per barrel of the pipeline looping project. We have a long way to go in terms of getting to 100%. To answer the rest of your question, we could easily sign up 100%, but we do want to keep some available for interruptible shippers. We wouldn't contract the whole pipeline 100% under 10-year take-or-pay. We'd probably stop short of that.
Okay. That's helpful color. Last question, if I could. Just really from, I guess perhaps the all-in O&M 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 cost per barrel over time as we grow, I perceive it will be flat or decreasing per barrel just because of economies of scale.
Yeah.
Okay.
Carl, keep in mind that 2015, we'll have a full year of Resthaven, we'll have a full year of the Vantage Pipeline, we'll have our phase two costs, we'll have Saturn two costs. OpEx overall will go up just by the nature of increased assets coming into service. In terms of Q4, there was some slightly higher costs. Again, that was mainly new assets. Conventional was up slightly. A large portion of the conventional increase was due to the Western Pipeline System, and if you recall, that's a cost of service type pipeline, so those OpEx will be recovered through revenues. We had a one-time slope replacement on one of our pipelines. 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 0 lost time injuries.
Thank you very much.
I just want to follow up a little bit on the hedging. You gave your comments there, it seemed directed towards NGL marketing, but I'd ask the same 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 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. In the past, the company has put in place U.S.-based hedges, but then you still have the basis differential open. It's not perfect, but we are looking at those possibilities.
Yeah, 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. When you look at the upcoming NGL year, does the current price environment give you an ability to recontract 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 keep in mind, a lot of the propane we market is 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. If you go forward, keep in mind RFS II and RFS III, notwithstanding we're marketing that propane, we are doing it as agent. So 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?
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. 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 CAD 4 or CAD 4.5 billion of remaining projects, and we can save 5%. That's actually a much larger number than what propane just changed. There is a silver lining in this environment for us to take advantage of really lower costs across the board. That's a high focus area for us right now.
Nothing you've seen to detract you from attaining that goal of the 5% improvement?
It's early days, but that's what our objective is.
Okay, 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 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 backs. 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 the propane we need to build 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. We don't need any more customers there. We just have to work our way through the approval process.
Right. 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. Over 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 to.
Steven, I think there's two 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. 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 4-5 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. It's a pre-build for that eventuality.
Will that pipeline be connected to a Pembina gas plant or one of the producer's gas plants?
Hopefully both, but right now, just producers.
Thank you. Those are my questions.
Have a good one.
Your next question comes from the line of Robert Hope from Macquarie. 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 where the rating agencies might be giving you a pass during the construction?
Yeah. In terms of the rating agencies, S&P reconfirmed our rating a week and a half ago, 2 weeks ago, at Triple B. They're well aware of the plans. In terms of our funding, nothing's changed from our stated 50/50 debt equity. That's how we're going to lay out the plan. The funding always is depending how much capital we spend in the year, how much cash flow we generate after dividends. We're a little early in the year to talk about that, Robert, but given 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. It sounds like, Scott, it's fair to say you're not sounding particularly concerned that where there may have been a need for equity in future years, it doesn't sound like right now you're thinking about accelerating that into 2015.
Well, certainly, if you look out over the next three 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 CAD 1.9 billion to maybe closer to CAD 2 billion because of the Vantage expansion and a few other small things. Then it becomes a function of will we get through the entire CAD 2 billion capital program this year, or will some of it slip into 2016? A lot of that depends, too, on regulatory approvals. Once we get regulatory approvals for some of our projects, we can order long-lead equipment. 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 that if you add capital to the plan, that could change things. How are you thinking about that right now, given there is some downward pressure on FFO? Are you changing the hurdle rates and looking at things that are either the most strategic things you need, or are you just taking the view that you're not particularly capital constrained, you've got good liquidity, so if you find something that you think is accretive, you're just going to go ahead and do it?
Robert, the answer to your question is we're always looking for those opportunities, and we haven't really raised our hurdle rates or become concerned on capital. We just had a great record pricing on our debt issue, and I think it was well oversubscribed. The market seems to be strong for us. In terms of overall opportunities, there is 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?
Yeah. I would say they're our traditional basins, so it's Montney, Deep Basin, and Duvernay. In terms of when they start up, they'll start up in mid-2017 and then ramping up through to mid-2018.
Okay. Is it roughly equally split among 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 CAD 100-110 million. Is that a quarterly base figure that you're looking at, or is that an annual number? Sorry about that. To ask you again.
No, that's our annual fee for service revenue that comes from our
Got you.
NGL portion of the business.
Thank you. I needed that. The other question, I've got two other ones for you. When you're looking at your income taxes rolling forward, have you 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. You 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. How should we be looking at your capital costs when a lot of these costs are going to be on the steel side? I'm thinking about the US dollar having moved.
Yeah. Both good observations. A fair amount of our tangibles for RFS II and RFS III, we've already bought, so we're not going to see big savings there. Steel generally is weaker. The U.S. dollar is stronger. Where we really see the savings is in construction costs, where there's just a lot less competition for construction services in the coming years. You think about the producers' reductions in capital. 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. 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, they're a bit of an offset then.
Yep.
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 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, truthfully, whether the price of oil and associated products was $50 or $150, we'd be doing the same things. I think in this environment, the difference is we think we can implement our project pipeline maybe a little more cheaply than we thought we could previously.
Mick, is there any type of 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 you'd be more interested in now?
I wouldn't say related to a specific geography the way you've described, but we are obviously thrilled with Vantage. If you do the multiple analysis inclusive of the expansion and assuming that it's almost full, maybe not quite. It's been a wonderful acquisition for us. More fee-for-service assets and usually adjacent or connecting to our infrastructure 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. Our strategy remains intact.
Last question related to this is, you guys have a premium organic growth slate in front of you, and you don't need to do acquisitions, but I think you mentioned maybe that acquisitions are a little more attractive now than they would've been. Is that rising in your priority list?
Yes, it is. 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. What we do have a sense of is there's going to be a lot more deal flow. Some producers, for example, that would've never considered monetizing a gas plant or something like that, may just want to do that in this market. We're just seeing a lot more opportunity. I don't know that it'll be less expensive. Interest rates are going down. Cost of capital in our business aren't really going up. It's just too early to see whether we can buy cheap.
Probably just wait a few more months.
Maybe.
Thank you. Those are my questions.
Thank you.
Your next question comes from the line of Steven Paget from FirstEnergy Capital. Your line's 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, there doesn't seem to be incremental ethane demand at this time.
Yes.
You know, for example, with RFS III, we didn't put in the last tower to take out ethane. We're positioning our business to add that capability in the future. With commodity prices the way they are, only the highest value products are worthy of extraction right now. Generally, we're seeing an industry move away from ethane plus to a more dew point plant or minus 40 type plants. They're not quite as hungry for the NGLs, which could be the foreseeable future. As basins mature and commodity prices get back to normal, whatever timeframe that might be, we do think that'll eventually come as it has over many decades in the past. 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, or the CAD 1.7 billion, and compare the listed projects from your recent presentation, there's about CAD 200 million in smaller projects. Are those mostly related to conventional pipelines and cavern storage?
Yes, as well as potentials for some. Yeah, that's right, Steven. Yeah.
Well, thank you. As you bring on the next CAD 5.7 billion in assets, do you plan to maintain the same dividend payout ratio?
Well, the ratio's been changing quite a bit with the change in commodity prices, so I don't know which ratio you're referring to necessarily, but 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 I think it's a matter of timing. Keep in mind that the CAD 700 million of incremental EBITDA, that's all long-term, fee-based income. That's kind of our contractual floor. Even the math on that would indicate we should have upward mobility in the dividend, and if we get anywhere close to full, significant upward mobility. Now it's just a matter of us getting comfortable that the projects that we believe are on time and are on budget come in that way.
As you mentioned, we have CAD 1.5 billion, and if we get CAD 2 billion through that, I think we're going to be feeling really comfortable about dividend increases in the future.
It's fair to say that the dividend policy has leaned to a 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 out at the marketplace, do you see any difference or any preference between U.S. versus Canada?
I would say, most of the opportunity that we're aware of is in Canada because this is where we live and it's the basin we know the best.
Mm-hmm.
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. Beyond that and beyond, of course, Sarnia, Corunna, Central Canada, we have, as a company, limited knowledge and henceforth, more nervousness. 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. 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.
You did mention producers, and is it mainly producers that you're feeling 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 needs for alternative sources of capital. That would be, in my estimation, the most likely source of assets.
All right. On the propane and ethane, you certainly talked a bit about the, 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?
Pipe's always better, in my opinion, than rail for many reasons. They're 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 U.S., and if you want to go to the coast, you got to cross the mountains. The cost there would generally mean you need 200,000-300,000 barrels a day, I'd say, as a minimum, to have the economies of scale to do something like that. The basin just doesn't have that kind of volume today. In the future, if the Montney and the Duvernay live up to their potential, there could foreseeably be critical mass to do something like that.
One last question. In terms of the CDH, what sort of demand are you seeing? It's kind of been out there as a concept now for a little while. How is 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 gonna go? 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 are 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 a incident-free year. Again, congratulations to all our staff, and thanks for your continued hard work. For those on the phone, thanks for your support. With that, we'll sign off. Have a nice weekend.
This concludes today's conference call. You may disconnect.