Good morning, ladies and gentlemen. My name is Sally and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation's Q4 and annual 2015 financial 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. I will now turn the call over to Scott Burrows, Vice President of Finance and Chief Financial Officer. Please go ahead, Mr. Burrows.
Thank you. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our fourth quarter and 2015 annual results. I'm Scott Burrows, Pembina's Vice President of Finance and Chief Financial Officer. Joining me today is Stu Taylor, Senior Vice President, and 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, which we released yesterday after markets closed. Mick will then provide an update on Pembina's growth projects and make some closing remarks before opening the Q&A session. 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, judgments, projections, and risks. 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 could differ materially from the forward-looking statements we may express or imply today. I would also encourage listeners to review the news release, MD&A, and financials we issued yesterday, which provide our full fourth quarter and annual results as of December 31st, 2015, as I won't go over each financial metric on today's call. 2015 was a milestone year for Pembina, including record financial results and revenue volumes across our conventional and gas service segments. We're raising approximately CAD 2.3 billion of capital, including our DRIP proceeds, and announcing CAD 600 million of new capital projects.
We brought into service approximately CAD 1.3 billion of projects safely on time and on budget, and in some cases, even better. Collectively, these assets will provide CAD 100 million-CAD 150 million of incremental fee-for-service EBITDA in 2016, helping to further strengthen Pembina's financial position and protect us from volatility in the commodity markets. In spite of the uncertainty our industry has experienced, Pembina is cautiously optimistic for 2016. We expect to commission approximately CAD 1.2 billion of large-scale expansion projects, which are backed by long-term fee-for-service contracts. Furthermore, we have strong financial foundation and sufficient liquidity to fund our remaining growth projects. Pembina continues to build out our fee-for-service asset base. In total, fee-for-service revenue streams represented approximately 80% of Pembina's operating margin for 2015.
Of the total fee for service, over 70% was composed of contracts that mitigate volume risk, including cost of service or take-or-pay arrangements. In the quarter, Pembina generated EBITDA of CAD 260 million compared to CAD 170 million in the fourth quarter of 2014. The 53% quarterly increase was largely as a result of higher operating margin, partially offset by increased general and administration costs. Additionally, our fourth quarter 2015 EBITDA was also impacted by other items, including the sale of Line Fill and project derecognition costs totaling CAD 10 million. Excluding these items, our EBITDA would have been CAD 270 million. For the year 2015, EBITDA totaled CAD 955 million as compared to CAD 920 million in the same period in 2014. The annual increase was largely driven by higher operating margin as general administration costs were consistently year over year.
Adjusted cash flow from operating increased to CAD 280 million during the fourth quarter, or CAD 0.77 per share, from CAD 164 million or CAD 0.49 per share for the same quarter last year. For the full year, adjusted cash flow from operating activities was CAD 878 million or CAD 2.53 per common share compared to CAD 777 million or CAD 2.38 per common share for the same period. The increase in quarterly and annual adjusted cash flow is principally as a result of higher operating margin, lower current tax, and lower share-based compensation expenses, offset somewhat by increased preferred share dividends and higher shares outstanding. Revenue volumes in Pembina's conventional business continued to be resilient. 2015 represented record annual throughput of 614,000 barrels per day as compared to 575,000 barrels in 2014.
In the fourth quarter, revenue volumes averaged 621,000 barrels per day as compared to 612,000 barrels per day in the fourth quarter of 2014. Revenue volumes were also very strong in January 2016, averaging in excess of 650,000 barrels per day. Increased revenue volumes quarter-over-quarter were attributable to Phase II Expansion, which was fully commissioned during the fourth quarter, increased volumes on the Vantage Pipeline, as well as new connections. These factors contributed to operating margin of CAD 109 million in the fourth quarter of the year, which is 47% higher than the CAD 74 million in the same period last year. On a full year basis, operating margin was CAD 401 million or 33% higher than the CAD 302 million reported in 2014 for the same reasons as I discussed previously.
2015 was a significant year in the gas services business, with a 27% increase in revenue volumes as compared to 2014. This increase was driven by our Resthaven and Musreau II gas plants that went into service in late 2014. Annual operating margin increased to CAD 144 million as compared to CAD 107 million in 2014. On a quarterly basis, operating margin was CAD 33 million compared to CAD 29 million in the fourth quarter of 2014. Quarterly volumes were impacted by an unscheduled outage at our Resthaven facility, which was placed back into shallow cut service in February. Like our conventional business unit, we are seeing strong volumes in our gas services in 2016. In February, we recently exceeded over 1 Bcf a day, which is a new record for Pembina. In our oil sands and heavy oil business, we saw steady performance as expected.
Fourth quarter operating margin was CAD 36 million versus CAD 34 million in 2014. For the full year, operating margin was CAD 139 million, compared to CAD 136 million for 2014. In the midstream business, operating margin was CAD 123 million during the fourth quarter of 2015, which was meaningfully higher than the CAD 57 million recorded in the fourth quarter of 2014. The significant increase in quarterly results was largely a result of an inventory impairment recorded in the fourth quarter of 2014. Additionally, increased margin on sales contributed to higher operating margin. For the full year, operating margin was CAD 427 million as compared to CAD 528 million in 2014. The decrease on a year-over-year basis was largely attributable to lower commodity prices and tighter price differentials. Going forward, Pembina will be commissioning a major asset in nearly every quarter into 2017, which will help to further increase Pembina's fee-for-service supported cash flows.
In aggregate, these projects represent a total investment of just over CAD 5 billion and are set to contribute between CAD 600 million to CAD 950 million of incremental EBITDA by 2018, depending on utilization and commodity prices. I will now pass the call over to Mick, who will give an update on how our growth projects are progressing.
Good morning, everybody. First and foremost, I want to recognize the commitment to safety that Pembina's staff continues to demonstrate every day. I'm extremely proud to say that Pembina has now exceeded two years without any employee lost time injuries. Since the beginning of 2014, Pembina's employees have worked over 5.1 million hours, which represents an 18% increase over 2014. 2016 represents another exciting year for Pembina, since many large-scale projects that we have been talking about for many years are coming into service. A large portion of these projects will be online in a matter of months, including RFS II, the Horizon Expansion, two new gas plants, and additional NGL infrastructure at Redwater. These projects are backstopped by long-term fee-for-service contracts, most of which have substantial take-or-pay or fixed return provisions.
Growth and stable cash flows will help to further insulate Pembina from volatility in commodity markets and provide a solid foundation to support both current and future dividends. Throughout 2015, we commissioned our Phase II Expansion. The crude oil and condensate portion was commissioned in April, and the NGL portion was placed into service mid-September, collectively adding 108,000 barrels a day of capacity. We're looking forward to benefiting from a full year contribution from these large-scale expansions in 2016. As Scott mentioned earlier, volumes remain very strong across all our conventional pipeline systems. We have now completed approximately 30% of the overall Phase III Expansion project. The Phase III Expansion represents Pembina's largest growth project, and we are very pleased with the progress to date as it continues to trend on time and on budget.
Over the course of 2015, a 70 km section between Kakwa and Simonette was placed into service. We expect to receive written decision from the AER next month on the Fox to Namao portion of the project. All regulatory approvals have been received, and construction is well underway for the Carr Lateral. This project will link growing Montney production volumes in Pembina's Phase III Expansion project and is expected to come online in early 2016. This project is tracking moderately above budget, but this slight overrun is economically mitigated by agreements supporting the project. The Vantage Expansion construction is also nearing completion. The pipeline portion is largely finished and final commissioning work is underway. The pump station portion has received all required approvals and design work is now complete. Currently, the project is tracking under budget.
In spite of a challenging commodity price environment, Pembina continues to receive strong support from customers. Subsequent to year-end, we entered into an agreement to construct a new lateral in the Altares area of British Columbia with a capacity of 17,000 barrels a day. This project is underpinned by a long-term cost of service agreement. The capital cost is estimated at CAD 70 million, and subject to regulatory and environmental approvals, is expected to be in service by mid-2017. Developing this lateral helps provide incremental Phase III volumes and as well as extending the reach of our gathering network into the B.C. Montney. Civil work on the Horizon Expansion is also currently underway, and most regulatory and environmental approvals have been received. This expansion will increase the pipeline capacity to 250,000 barrels per day and is expected to be in service by mid-2016. Now on to gas services.
In 2015, 260 million cubic feet per day of gas processing capacity and supporting pipelines were placed into service. These projects were largely developed on schedule or better and under budget. 2016 is set to be a milestone year for Pembina's gas services business unit, as well as we will be commissioning an additional 200 million cubic feet per day of processing capacity. The Resthaven gas plant expansion continues to progress well and is now approximately 80% complete. The project is expected to be in service by mid-2016 and is trending under budget. Our Musreau 3 facility is now approximately 75% complete. We expect the facility to be in service by mid-year, and we expect it to come in under budget.
In November, we announced the development of a 100 million cubic feet per day Duvernay I gas plant. This project represents the first large-scale gas plant designed specifically for the Duvernay. We have received AER approval for the plant and are now focused on securing regulatory approval for the associated pipeline. Subject to receiving all regulatory and environmental approvals, Duvernay I is expected to be in service in the second half of 2017. Once all these facilities are commissioned, total processing capacity is expected to reach approximately 1.6 billion cubic feet per day. These plants are concentrated across the most economic resource plays in Western Canada. Moving on to midstream. At the Redwater site, we are nearing completion of our second 73,000 barrel per day fractionator, which is expected to be online by the end of March.
This represents a major accomplishment for our midstream business, and I'm happy to say the project will be substantially on budget. It's actually being commissioned as we speak. RFS 3 is also progressing well. Over 50% of the long lead items are now on site, and construction of piling and foundations is complete. We expect RFS 3 to be in service in the third quarter of 2017 and is trending on time and on budget. Once complete, our Redwater site will be the largest fractionation facility in Canada, with over 200,000 barrels per day of nameplate capacity. Pembina is progressing work for a major terminalling project in support of North West Redwater Partnership's planned refinery. Substantially all long lead mechanical items have been ordered, and detailed engineering procurement is now 40% complete. Subject to regulatory and environmental approvals, the project is expected to be in service by mid-2017.
At our Edmonton North Terminal, we continue to advance construction of three above-ground storage tanks with a total capacity of 550,000 barrels. Electrical work is nearing completion, and the team continues to progress mechanical integration. The project is on schedule to be in service by mid-2016 and is currently trending on budget. Finally, as Scott mentioned earlier, we wrote off certain non-transferable costs related to our proposed Portland West Coast Terminal. After careful consideration, we decided to no longer pursue that location. We do, though, remain committed to developing a West Coast terminal to help our customers access premium international markets. Scott, back to you.
We are very happy to have access to capital markets throughout 2015 and now into 2016. During the fourth quarter, we completed a common share offering for gross proceeds of CAD 460 million. In total, throughout 2015, Pembina raised approximately CAD 2.3 billion of debt and equity capital. In January, we completed a preferred share offering for gross proceeds of CAD 170 million. As of February 24th, 2016, our CAD 2 billion credit facility is completely undrawn, and we have a modest cash balance of CAD 37 million. The combination of sustained access to capital markets and an undrawn CAD 2 billion credit facility creates a robust financial foundation to fund the remaining portion of our CAD 2.1 billion capital plan for 2016 and positions us well to fund the remainder of our secured growth projects through the end of 2017.
Maintaining our investment-grade credit rating and a strong balance sheet to ensure financial flexibility is paramount to Pembina. With that, I will pass the call over to Mick to wrap things up before opening the line for questions.
Thanks, Scott. In closing, I wanted to say we recognize this is a challenging time for our customers. We value all our producer relationships and are committed to doing what we reasonably can to help improve their netbacks. I'm very proud of what the Pembina team has accomplished in what has been a challenging time for our industry. All of our businesses operated soundly, and we made many strides towards achieving our long-term growth objectives while supporting communities we work in. I'm confident that Pembina's strategy will achieve its objectives by continuing to de-risk our business and commission large-scale fee-for-service assets, providing high-value services for customers. In just 18 months, we'll have commissioned nearly all of our CAD 5 billion of secured projects. With that, I want to thank everybody for continued support of Pembina and participation in this morning's call.
One thing before I turn it back to the operator. We're going to do a little survey this morning to see what you think about the format of our call. If you'd like our call script to be shorter and have more time for questions, or you like it the way it is, or have any other ideas. With that, I'll turn it back over to the operator.
Thank you. As a reminder, if you would like 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 with TD Securities. Your line is open.
Thank you. Congratulations on another strong quarter.
Thanks, Linda.
I realize you're quite busy in executing on your capital projects, but, as you can appreciate, there's a lot of producer midstream and energy infrastructure assets that are purported to be coming up for sale or if not already for sale. I'm just wondering if I can get a sense of how you kind of balance your capital allocation decisions what sort of capacity you think you might have and how you think of, not just regular operating risk, and clearly financing is a bit more of a consideration than it would've been previously, but also counterparty and other risks associated with looking at these things.
Thanks, Linda. Yeah, we vigorously look at everything that is for sale, and the challenge or the magic maybe has been to try to anticipate fully what the cost of capital for the industry is in this new world. We are looking at all kinds of projects across business units. Really, we're not really too sensitive about what business unit a project ends up in. We're really focused on the soundness of geology, the ability to enhance the value of all of Pembina through a given greenfield, brownfield or M&A project and the vertical integration opportunities. Clearly, counterparty credit has been an issue. We just had a long session with our board yesterday on the economics of the regions we serve and the economics and financial health of our customers.
It is remarkable how resilient our producer customers are and the steps they've been able to take to watch their costs. We're doing what we can to help them out. Generally, because we're not a really significant service provider to regions that have WCS product, in the oil sands we're synthetic crude, which remains quite cash flow positive. Then you look at the Cardium, the Deep Basin region, Montney, Duvernay, they're still pretty darn competitive and still are generally cash flow positive. In fact, they're all cash flow positive. Not every producer, not every well, but the regions are still able to turn positive cash flow. We've given that a lot of thought, and our conclusion is we're going to stick with our strategy. We're not going to do anything different. We'll follow our investment criteria very rigorously.
We are just beefing up our review of counterparty credit. By way of example, our risk management committee used to meet quarterly. We're meeting monthly right now just to stay completely on top of that. You may know that we've significantly, over the last three years, enhanced the depth and capability of our counterparty credit group. Again, it's just one of those things where we've been preparing for tougher market conditions for three to five years. I hate to say that that was time well spent because I'd rather have the whole industry at better health. We have been positioning our business for resilience. Scott, do you want to add anything on the financing?
Yeah, I think, Linda, we still believe that we have decent access to capital. As we pointed out, we have a CAD 2 billion undrawn credit facility. From that perspective, we think that we could look at acquisitions or greenfield opportunities of various sizes.
Thank you. Just a cleanup question. Cash taxes for 2016 and beyond, what are you seeing in terms of trends off of 2015?
For 2016, it's probably likely in the neighborhood of CAD 100 million-CAD 125 million.
Okay. Trending up in 2017?
It's probably more stable just because you think about what we're bringing on RFS II, RFS III, and gas plants. Those are all high write-off assets. I don't expect it to trend up material in 2017.
Great. Thanks, Scott.
Your next question comes from the line of David Galison with Canaccord Genuity. Your line is open.
Good morning, everyone.
Morning.
Just had a quick question on the guidance for 2018. Adjusted EBITDA came in for 2015, you did around CAD 978 million. Is that correct?
That's correct.
Adding the CAD 600 million-CAD 950 million will take us to around CAD 1.6 billion-CAD 1.9 billion for 2018. Just for me to understand, is the 1.6 based on the 777 million barrel per day capacity that you've got committed for?
No. Remember that the 777 is our firm contracts. Most of our firm contracts have 75% take-or-pay. Recall, the CAD 600 million of that range is really meant to represent the take-or-pay level, whereas more than 900 is more of a normal utilization as well as some commodity impact from the sales at the back end of RFS II and III.
Oh, okay. Then just on the conventional side, I know that you've been surveying customers and just wanted to know if anything has changed since the last time you surveyed them. Are there any changes in their views of the nominations they made for the conventional side?
We have very close contact with our largest existing and future customers. So far what we've heard from them was that their nominations were realistic, if not conservative, and all but a few foresee themselves being at or above take-or-pay levels. Clearly, capital isn't available to all the customers, and some will no doubt come in under take-or-pay. We are working with customers to where we can, mix and match nominations with people who may have more capacity than they need, with those who need more. We're going to balance that with the promises we're making to shareholders. We're not going to do that at our detriment, but where we can, we're going to be flexible with matching customer demands up.
Okay. Just on, as well on the conventional side, just wondering with Phase II complete, how are you seeing volumes trending in 2016?
Yeah. Well, I'll answer that in a couple of ways, because we have got the question. If you recall the LDP portion of that commissioned in April, and really what we started to see as far back as Q4 of 2014, was a lot of those barrels were drilled and wanted to hit our system. Because Phase 2 was not in service, those volumes were being trucked to our Drayton Valley and our Swan Hills. You actually started to see the Phase 2 volumes show up as far back as Q3 and Q4 of 2014. When that pipeline came online in April, you saw a shift of volumes from our Drayton Valley and Swan Hills back onto the Peace system once that system was debottlenecked.
That's really why you didn't see an incremental 50,000-100,000 barrels a day in April when that project came online, because a lot of those barrels were already hitting the system. We have seen production continue to increase. You saw Q4 2015 be quite strong. As we pointed out, both in our annual report and in our call today, we saw volumes in January in excess of 650,000 barrels, which, if I recall, is the highest month in the company's history.
Okay. Thank you very much.
Your next question comes from the line of Steven Paget with FirstEnergy Capital. Your line is open.
Thank you and good morning. Maybe you could comment on where propane is going out of Alberta, as outside Alberta itself, the U.S. Midwest market is the most important market. Are you seeing any signs that LPGs out of the Marcellus region are closing the U.S. Midwest market off to Alberta LPGs?
Steven, it's Stu Taylor. We haven't seen that as of yet. Our propane marketing group is very active in the markets, looking for locations, and we're continuing to move barrels. We've had a great success with our inventory and drawing down our inventory through 2015. We're very excited about where we're sitting today in 2016. We have, at this point in time, not seen a closing down of those markets, but they monitor that on a daily basis. They would be aware if that market was closing, but have not experienced it yet.
I would just add that we've seen over the last 4 to 5 weeks pretty significant propane draws. Almost, if you go back 6, 7 months, we were quite a bit above the 5-year average. With what's happened in the U.S., both exports out of the Gulf Coast and Northeast weather, we've seen that inventory level come down almost to the top of the 5-year average. What that's really done is drawn up the Mont Belvieu price. I think in January we were $0.34-$0.35. We're now on a spot basis up to $0.41. As Belvieu has increased, that's dragged up both Conway and Edmonton.
Okay. Scott, Stu, thank you. Maybe we could talk more about exports of LPGs out of North America. Assuming the market is basically integrated, we have to look beyond to what these other markets are taking. How much in particular do you think the Asian market can take? As I understand, it's taking about 200,000 barrels a day right now. If that's saturated, does North America run out of places to export its surplus production?
I think you have as good of an idea of the answer to that question as many, Steven. The long-term trend has been that Asia is looking for new propane markets, not just based on price, but also based on supply diversity. There's still a lot of interest for North American propane. You saw Enterprise recently upped their capacity. We know there's cargoes moving out of Ferndale. We still get a lot of inbound interest from Asia. I think, even if the world is a little different today than it was a year and a half ago due to commodity prices, we think the long-term trends remain and that location and cost-advantaged propane in Alberta will find its way to market. It only makes sense.
Well, thanks, Scott. I'll follow up with my thoughts on the call format with Ian and Chelsea.
Steven, what do you think about our call format? How do you feel about the script? What would you do differently?
You want to discuss this right here?
Yeah. Just a one-minute overview of what you think.
I would cut the script down to not just, "You've read the release. Do you have any questions?" but a very short commentary on the construction projects and
... any threats to growth or a breakdown of growth, particularly between fee for service, take or pay, et cetera. The division of the contracts by contract type is always very useful.
Okay, thank you.
Your next question comes from the line of Andrew Kusky with Credit Suisse. Your line is open.
Good morning. I guess the question's for Mick. Obviously, the royalty changes in Alberta have created some uncertainty for producers in the entire community. The question really is, have you seen any behavioral changes at this point in time from the producer community because of the uncertainty in the royalty environment?
They really didn't change very much, and depending on where you sit in the basin, there's still details to come out, of course, but the initial discussions I've had with some of our CEO customers is they're relieved at how subtle the changes are and that they should not be negatively impacted. I think most people were anticipating larger changes. They were bracing for adverse changes. I think that, generally, capital markets and producers are feeling quite positive compared to how they felt, say, two months ago about those changes.
Okay. That's helpful color. Maybe just a follow-up, are you seeing any kind of evolution of your contracts with the producing community on just processing as we're in this commodity downturn right now?
No. Honestly, we're business as usual. The deals we did last year, the deals that we're looking at still now are just regular vanilla kind of deals that you've come to expect from us. Again, we did the big review with our board yesterday on the state of the nation, our revised five-year plan and all that, and we concluded our strategy. If you think about back over the last three years, we've had the same strategy. We tested that strategy. Could it work in very robust times? Unfortunately, last year, we had the privilege of testing it in horrible times. In the very good times, we grew like crazy, and in the very bad times, we still grew a bit, and all the while, we showed amazing resilience. We don't disclose budget numbers, but now that it's in the rear-view mirror, we almost made our budget.
I'm talking within 2%-4% of our budget, which was set October 14, before any of this bad stuff happened, and we almost still made it. I think our strategy is extremely resilient and has proven successful in both highs and lows.
if I may just follow up to that, do you see yourselves as positioned right now at a very good base, earning acceptable returns on the capital you employed and then effectively getting a bit of a multiplier effect, one from commodity prices rising, and then two, just from the interconnectivity of your networked assets?
No, I actually don't think we're getting fairly treated by markets given the level of fee for service business we have. When I go through all the new projects, it's kind of boring because it's on time and under budget, and they're all highly contracted. I just do the math on the guidance we've given, and I think there's lots of room. I don't think we're getting any credit for the possible CAD 30 million of EBITDA improvement for 10-cent increase in propane prices. I don't see that anywhere in our stock price. I think there's tremendous opportunity out there. That said, I'm like every other investor, and when's the right time to pile back into a story is really, I think, what the question is. I think people know there's a lot of money to be made in upstream and in midstream.
It's just when's the right time to do it.
Okay. That's very helpful. Thank you.
Your next question comes from the line of Ben Pham with BMO. Your line is open.
Okay. Thanks, and good morning, everybody. I wanted to go over your 80% fee for service target for 2018, and perhaps you can help me a little bit on how that's flexed over time relative to where the commodity price curve expectations are. Obviously, you got a component of commodity pricing impacting the commodity price business. Also you got potentially higher commodity pricing driving utilization and firmer contracts. I'm just wondering how those two things interplay because they kind of move against each other and how that flexes at 80%.
If you go back to 2014, we were about 68% fee for service and about 14% frac spread, with the difference being our product margin business. As we went through 2015, that 68% fee for service increased to 80%, and the frac spread went from 14% to basically 0. That was a combination, Ben, of both our fee for service on aggregate being up in the neighborhood of CAD 100 million-CAD 120 million and our frac spread
Going from CAD 100 million to basically zero. That's the math that got us from 68% to 80%. It was both of those. As we dial forward to 2016, we do believe Empress will be profitable in 2016. That frac spread again could be in the neighborhood of CAD 30 million-CAD 40 million, which would then increase. We also have fee-for-service assets coming into service. When we look forward to 2016, we're still guiding towards that 80% fee-for-service, which is a combination of growth in our fee-for-service business on a dollar basis. We also have increased contribution from the frac spread.
To answer the rest of your question, when you look at 18, we think we can be 80% or greater again, because we're ramping up our fee-based business. The commodity business is based on our prediction errors based on strip pricing. In absence of other M&A activity or changes, the only way our commodity exposed businesses would grow more than 20% is if we were making an unbelievable amount of money from them. The kind of 80 or higher in 2018 is based on strip pricing.
Okay, thanks for that. I'd like to touch base on your Phase III conventional project now as you go through the regulatory process and discussions with landowners and whatnot. Does that necessitate possibly a re-look at your CapEx?
No, we've concluded all of our field work, with landowners, First Nations. We expect a ruling here in the next month. We're right at the tail end of that. Knock on wood, we hope we'll be given the go ahead before our investor day.
Okay, thanks everybody.
Thank you.
Again, if you would like to ask a question, please press star one on your telephone keypad. Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open.
Morning. Maybe I'll just first start following up on, Scott, what you were saying around Empress and the expected profitability in 2016 versus frac spreads being zero in 2015. Maybe by saying that you've answered the question. Can you just comment on the 2016 gas year and with respect to what you were saying on the extraction premiums and whether a reduction there is what's really opening up the profitability for 2016?
Yeah, it's all the components, Robert, and I'm not going to get into detail for obvious reasons. What we're seeing is lower AECO pricing, lower extraction premiums, and Sarnia continues to have that kind of $0.15 propane premium. When you factor all three of those things in, that's really what's leading to the profitability.
Okay. Maybe just to kind of follow up on that. Ex extraction premiums, are you expecting a material increase in frac spreads then, 2016 versus 2015?
Well, yeah, because we are seeing a slightly higher price on the propane and natural gas is lower. Those are contributing to the profitability as well.
Okay. When you're looking at the propane price, you're looking at Sarnia, though you're not looking at an Alberta-based price?
Correct.
Okay.
Correct.
Just with respect to contracts, and Mick, you'd mentioned earlier that you're kind of trying to mix and match and swap barrels for your customers and trying to facilitate that as a way to help them all out, and that you're not looking to do anything that's detrimental from a shareholder perspective. How do you think about that? Or would you consider a restructuring of agreements, maybe some lower upfront tolls or fees if you can extend term or get some escalators, i.e. would you do deals that might be NPV positive to you, if it meant helping customers out on the front end?
It's a great question and you provided a great summary of what we're trying to do. We have to be balanced. If we were to extend everyone's contract, then we wouldn't be able to stand behind the guidance of how much EBITDA we're going to add over the next few years. We have to be mindful that EBITDA is required to pay dividends and reinvest cash flow. It is a balancing act. Under certain circumstances, we could reshape contracts to be NPV neutral or NPV positive, provided we have a very high likelihood of using that then free capacity for another purpose. It really is situational and it depends on what we're doing with a particular producer customer and how much of our integrated value chain they're using.
I think it'd be wrong for me to generalize, but I can tell you that we are doing what we can to help customers without detrimentally affecting our guidance or the value to our shareholders. What we have been doing there has been very well received.
Okay, great. If I can just ask one last cleanup question here. Do you have what the dollar impact was of the Resthaven outage, whether that's in aggregate to margin or revenue and OpEx separately?
Yeah. CAD 3 million, Robert.
CAD 3 million to margin?
Yes.
Okay, great. Thank you very much.
Robert, one more question. Are you still on? Okay. Next. Looks like there's no more questions. With that, on behalf of Mick, Stu, and the entire Pembina executive team, thank you very much for your continued support, and we look forward to talking to you in May with our Q1 results.
This concludes today's conference call. You may now disconnect.