Pembina Pipeline Corporation (PBA) Q4 2015 Earnings Report, Transcript and Summary

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. [Operator Instructions] 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 am Scott Burrows, Pembina’s Vice President, 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 will 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 to the Q&A session. I would like to remind you that some of the comments made today maybe 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 31, 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, raising approximately $2.3 billion of capital including our DRIP proceeds and announcing $600 million of new capital projects. We brought into service approximately $1.3 billion of projects safely on time and on budget and in some cases, even better. Collectively, these assets will provide $100 million to $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 $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 contract and mitigate volume risk, including cost of service or take-or-pay arrangements. In the quarter, Pembina generated EBITDA of $260 million compared to $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 linefill and project derecognition costs totaling $10 million. Excluding these items, our EBITDA would have been $270 million. For the year 2015, EBITDA totaled $955 million as compared to $920 million in the same period in 2014. The annual increase was largely driven by higher operating margin as general and administration costs were consistently year-over-year. Adjusted cash flow from operating increased to $280 million during the fourth quarter or $0.77 per share from $164 million or $0.49 per share for the same quarter last year. For the full year, adjusted cash flow from operating activities was $878 million or $2.53 per common share compared to $77 million or $2.38 per common share for the same period. The increase in quarterly and annual adjusted cash flow was 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 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 2 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 $109 million in the fourth quarter of the year, which is 47% higher in the $74 million in the same period last year. On a full year basis, operating margin was $401 million or 33% higher than $302 million recorded 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 $144 million as compared to $107 million in 2014. On a quarterly basis, operating margin was $33 million compared to $29 million in the fourth quarter of 2014. Quarterly volumes are 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 today, 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 $36 million versus $34 million in 2014. For the full year, operating margin was $139 million compared to $136 million for 2014. In the Midstream business, operating margin was $123 million during the fourth quarter of 2015, which was meaningfully higher than $57 million recorded in the fourth quarter of 2014. The significant increase in quarterly results was largely resulted in 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 $427 million as compared to $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 $5 billion and are said to contribute between $600 million to $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 everyday. I am extremely proud to say that Pembina has now exceeded 2 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 in 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 2 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 are looking forward to benefiting from a full year contribution from these large scale expansions in 2016. As Scott mentioned earlier, volumes remained very strong across all our Conventional Pipeline systems. We have now completed approximately 30% of the overall Phase 3 expansion project. The Phase 3 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-kilometer 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 Karr Lateral. This project will link growing Montney production volumes in Pembina’s Phase 3 expansion project and is expected to come on line in early 2016. This project is tracking moderately above budget, but this slight overrun is economically mitigated by agreement 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 $70 million and subject to regulatory and environmental approvals is expected to be in service by mid-2017. Developing this lateral will help provide incremental Phase 3 volumes and as well as extending the reach of our gathering network into the B.C. Montney. Several work on the Horizon Pipeline 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 2016 – 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’s 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 our 100 million cubic feet per day, Duvernay 1 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 1 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 barrels per day fractionator, which is expected to be on line by the end of March. This represents a major accomplishment for our Midstream business and I am happy to say the project will be substantially on budget. It is commissioned – it’s actually being commissioned as we speak. RFS III is also progressing well. Over 50% of the long lead items were now on site and construction of piling and foundations is complete. We expect RFS III 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 our major terminalling project in support of Northwest 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, 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 into mechanical integration. The project is on schedule to be in service by mid-2016 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 $460 million. In total throughout 2015, Pembina raised approximately $2.3 billion of debt and equity capital. In January, we completed a preferred share offering for gross proceeds of $170 million. As of February 24, 2016, our $2 billion credit facility is completely un-drawn and we have a modest cash balance of $37 million. The combination of sustained access to capital markets and un-drawn $2 billion credit facility creates a robust financial foundation on the remaining portion of our $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 for opening the line for questions.

Thanks Scott. In closing, I wanted to say we have recognized this as a challenging time for our customers. We value all our producer relationships and are committed doing what we reasonably can to help improve their net-backs. I am very proud of what the Pembina team has accomplished and 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 am confident that Pembina’s strategy will achieve its objective 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 have commissioned nearly all of our $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, if people asking questions could, we are going to do a little survey this morning to see what you think about the format of our call, if you would 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. So with that, I will turn it back over to the operator.

Thank you. [Operator Instructions] 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 are quite busy in executing on your capital projects, but as you can appreciate there is a lot of preserve midstream and energy infrastructure assets that are reported to be coming up for sale or if not already for sale. And I am just wondering, if I can get a sense of how you kind of balance your capital allocations 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 have been previously, but also counterparty and another risks associated with looking at these things?

Thanks Linda. Yes. We vigorously look at everything that is for sale and the talent or the magic maybe has been to try to anticipate fully what the cost of capital for the projects across business units and really we are not really too sensitive about what business unit or project ends up in, we are 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 and it is remarkable how resilient our producer customers are and the steps they have been able to take to watch their costs. We are doing what we can to help them out. And generally because we are not a really significant service provider to regions that have WCS products, I mean, in the oil sands, we are synthetic crude, which remains very quite cash flow positive. And then you look at the Cardium, the Deep Basin region, Montney, Duvernay, they are still pretty darn competitive and still are generally cash flow positive. In fact, they are all cash flow positive, not every producer, not every well, but the regions are still able to turn positive cash flow. So, we have given that a lot of thought and our conclusion is, we will just – we are going to stick with our strategy. We are not going to do anything different. We will follow our investment criteria very, very rigorously. And we are just beefing up our review of counterparty credit. By way of example, we used to – our risk management committee used to meet quarterly. We are meeting monthly right now just to stay completely on top of that. And you may know that we have significantly over the last 3 years enhanced the depth and capability of our counterparty credit group. So, again, it’s just one of those things where we have been preparing for tougher market conditions for 3 to 5 years. And I hate to say that, that was time well spent, because I would rather have the whole industry at better health, but we have been positioning our business for resilience. Scott, do you want add anything on the financing?

Yes, I mean, I think Linda, we are not – we still believe that we have decent access to capital. As we pointed out, we have a $2 billion undrawn credit facility. So from that perspective, we think that we could look at acquisitions or Greenfield opportunities of various sizes.

Thank you. And just a cleanup question, cash taxes for 2016 and beyond, what are you seeing in terms of the trends of 2015?

For 2016, it’s probably likely in the neighborhood of $100 million to $125 million.

Okay. And then trending up in 2017?

Well, that’s going to – it’s probably more stable just because we are bringing on – you think about what we are bringing on, RFS II, RFS III and gas plants. Those are all high write-off assets. So, I don’t expect it to trend 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.

Good morning.

So, just have a quick question on the guidance for 2018, so adjusted EBITDA came in – for 2015, it is around $700 million – or $978 million, is that correct?

That’s correct.

Okay. So, adding the $600 million to $950 million will take us to around $1.6 billion to $1.9 billion for 2018. So, is the – just for me to understand, is the $1.6 billion based on the 777 million barrel per day capacity that you have got committed for?

No. So, remember that our – the 777 is our firm contracts, most of our firm contracts have 75% take-or-pay. So, recall with $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 sale for the back-end of RFS II and III.

Okay, okay. And then just on the conventional side, I know that you have been surveying customers and just wanted to know if anything has changed since the last time you surveyed them? And is there any – are there any changes in their views or denominations they have made for the conventional side?

We have – we have very close contact with our largest existing and future customers. And so far what we have 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 are going to balance that with the promises we are making to shareholders. We are not going to do that at our detriment, but where we can, we are going to be flexible with matching customer demands up.

Okay. And then just as well on the conventional side, just wondering with Phase II complete, how are you seeing volumes trending in 2016?

Yes. Well, I will answer that in a couple of ways, because we have got the question. If you recall that the LVP 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 and so because Phase 2 is not in service, those – but those volumes were being trucked to our Drayton Valley and our Swan Hills. So, you actually started to see the Phase II volume show up as far back as Q3 and Q4 of 2014. And so when that pipeline came online in April, you saw a shift of volumes from our Drayton Valley and Swan Hills back on to the P system once that system was debottleneck. And that’s really why you didn’t see an incremental 50,000 to 100,000 barrels a day in April when that project came online, because a lot of those barrels were already hitting the system, but we have seen production continued to increase. You saw Q4 2015 be quite strong. And 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. Your line is open.

Thank you and good morning. Maybe you could comment on where propane is going out of Alberta, 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 from two 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 are continuing to move barrels. We have had a great success with our inventory and drawing down our inventory through 2015. We are very excited of where we are sitting today in 2016. So, we have, at this point in time, have not seen a closing down of those markets, but they monitor that on a daily basis and would be aware of that if that market was closing, but have not experienced it yet.

I would just add that we have 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 in Northeast weather, we have seen that inventory level come down almost to the top of the 5-year average. And what that’s really done is drawn up the Mont Belvieu price. I think in January, we were $0.34, $0.35. We are now on a spot basis up to $0.41. And 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, it’s – you have to look beyond to what these other markets are taking and 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. And if that’s saturated, does North America run out of places to export its surplus production?

That’s I think you have is good of an idea. The answer to that question is many, Steven. Long-term, 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 is still a lot of interest for North American propane. You saw Enterprise recently up their capacity. We know there is cargos moving out of Ferndale. And we still get a lot of inbound interest from Asia. So I think it’s 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 in that location and cost advantage propane in Alberta will find its way to market. I mean, it only makes sense.

Well, thanks Scott. I will follow-up on – with my thoughts on the call format with [indiscernible].

Steven, what do you think about our call format and do you think we are – how do you feel about the script, what would you do differently?

Do you want to discuss this right here?

Just one minute overview of what you think?

I would cut the script down to not just you have read the – you have read the release, do you have any questions, but a very short commentary on the construction projects and any threats to growth or breakdown of growth, particularly between fee-for-service, take-or-pay, etcetera. The division of the contracts by contract type is always very useful.

Okay, thank you.

Your next question comes from the line of Andrew Kuske with Credit Suisse. Your line is open.

Good morning. I guess the questions for Mick and obviously, the royalty changes in Alberta have created some uncertainty for producers and the entire community, so the question really is have you seen any behavioral changes at this point in time from 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, it’s actually there are still details come out, of course. But initial discussions I have had with some of our CEO customers is they are relieved at how subtle the changes are and that they should not be negatively impacted. So I think that most people were anticipating larger changes. They were bracing for adverse changes. And I think that, generally capital markets and producers are appealing quite positive compared to how they felt, say two months ago about those changes.

Okay, that’s helpful color. And then maybe just a follow-up, are you seeing any kind of evolution of your contracts with the producer community on just processing as we are in this commodity downturn right now?

No. Honestly, we are a business as usual. The deals we did last year, the deals that we are looking at still now are just regular vanilla kind of deals that you have come to expect from us. And again, we did the big review with our Board yesterday on the state of a nation, our revised 5-year plan and all that. And we concluded our strategy. If you think about back over the last 3 years, we have had the same strategy. We tested that strategy, could it work in very robust time. And unfortunately, last year we have the privilege of testing it in horrible times. And in 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 rearview mirror, we almost made our budget, I am talking within 2% to 4% of our budget, which was set October 14 before any of this bad stuff happened and we almost still made it. So I think our strategy is extremely resilient and has proven successful in both highs and lows.

So then if [Technical Difficulty] 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 multiplier effect, one from commodity prices rising and then two just from the inter-connectivity of your networked assets?

No, I don’t think we are – I actually don’t think we are getting fairly treated by markets given the level of fee-for-service business we have the growth. I mean, when I go through all the new projects, it’s kind of boring because it’s on-time and under budget and they are all highly contracted. And I just do the math on the guidance we have given. And I think there is lots of room. I don’t think we are getting any credit for the possible $30 million of EBITDA improvement for $0.10 increase in propane prices. I don’t see that anywhere in our stock price. So I think there is tremendous opportunity out there, and – but that said, I am like every other investor and when is the right time to pile back into a story is really I think what the question is. I think people know there is a lot of money to be made in upstream and in midstream, it’s just when is 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 ‘18 and perhaps you can help me a little bit on how that’s flexed over time relatively to where the commodity price curve expectations and obviously got component of commodity pricing impacting the commodity price business, but also you got potentially higher commodity pricing driving utilization and from your contracts. So I just want to know how those two things interplay because they kind of move against each other and how that flexes 80%?

Maybe I will attempt to answer that question and see if I – I mean if you go back to 2014, we are about 68% fee-for-service and about 14% frac spread with the different 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 zero. So that was a combination then of both our fee-for-service on aggregate being up in the neighborhood of $100 million to $120 million and our frac spread going from $100 million to basically zero. So that’s the math they got us from the 68% to the 80%, it was both of those. As we dial forward to 2016, we do believe Empress will be profitable in 2016. So that frac spread, again could be in the neighborhood of $30 million to $40 million, which would then increase and we also have fee-for-service assets coming into service. So when we look forward to 2016, we are still guiding towards that 80% fee-for-service, which is a combination of growth in our fee-for-service business on a dollar basis, but we also have increased contribution from the frac spread.

And to answer the rest of your question, when you look at ‘18, we think we can be 80% or greater again because we are ramping up our fee base businesses. And the commodity business is based on our prediction there is based on strip pricing. The only way – 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. So – but the kind of 80% or higher in 2018 is based on strip pricing.

Okay, thanks for that. And I would like to touch base on your Phase 3 conventional project and as you go through the regulatory process and discussions with landowners and whatnot, I mean does that necessitate possibly a re-look at your CapEx?

No, we are through that whole, like we have concluded all of our fieldwork with landowners, First Nations. We expect to a ruling here in the next month. So we are right at the tail end of that and knock on wood, we hope will be given the go-ahead before our Investor Day.

Okay. Thanks, everybody.

Thank you.

[Operator Instructions] Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open.

Good morning. Maybe I will just first start following up on Scott what you were saying around Empress and the expected profitability in 2016 versus frac spreads being 0 and 15 maybe by saying that you have answered the question, but can you just comment on the 2016 gas year and with respect to what you were seeing on the extraction premiums and whether a reduction there is what’s really opening up the profitability for ‘16?

Yes, I mean, it’s all the components, Robert and I am not going to get into detail for obvious reasons, but what we are seeing is low ankle pricing, lower extraction premiums and Sarnia continues to have that kind of $0.15 propane premium. So, when you factor all three of those things in, that’s really what’s leading to the profitability?

Okay. Maybe just the kind of follow-up on that, so ex-extraction premiums, are you expecting a material increase in frac spreads then ‘16 versus ‘15?

Well, yes, because we are seeing a higher – a slightly higher price on the propane and natural gas is lower. So, those are contributing to the profitability as well.

Okay. And when you are looking at the propane price, you are looking at Sarnia, now you are not looking at Alberta?

Correct, correct.

Just with respect to contracts and Mick you had mentioned earlier that you are kind of trying to mix and match and swap barrels for your customers in trying to facilitate that as a way to help them all out, not looking to do anything that’s detrimental from a shareholder perspective. How do you think about that or would you consider restructuring of agreements maybe some lower upfront tolls or fee if you can extend term or get some escalators, i.e., would you do deals that might be MPV positive to you, if it meant helping customers out on the front end?

It’s a great question and you have provided a great summary of what we are trying to do. We have to be balanced. I mean, if we were to extend everyone’s contract, then we wouldn’t be telling you guys, we wouldn’t be able to stay – stand behind the guidance of how much EBITDA we are going to add over the next few years. So, we have to be mindful that, that EBITDA is required to pay dividends and reinvest cash flows. So, it is the 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. So, it really is situational and it depends on what we are doing with the particular producer customer and how much of our integrated value chain they are using. And so I think it would 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. And what we have been doing there has been very well received.

Okay, great. And 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 an aggregate to margin or revenue and OpEx separately?

Yes, $3 million, Robert.

$3 million to margin?

Yes.

Okay, great. Thanks very much.

Robert, one more question. Are you still on? Okay, next.

It looks like there is no more questions. So, 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.