Pembina Pipeline Corporation (PBA) Q4 2017 Earnings Report, Transcript and Summary

Good morning. My name is Chasa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation 2017 Fourth Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session [Operator Instructions]. Thank you. Mr. Scott Burrows, Chief Financial Officer. You may begin your conference.

Thank you. Good morning, everyone and welcome to Pembina's conference call and webcast to review highlights from the fourth quarter and annual 2017 results. I'm Scott Burrows, Pembina's Chief Financial Officer. On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer; Jason Wiun, Senior Vice President and Chief Operating officer, Pipeline and Jaret Sprott, Senior Vice President and Chief Operating Officer, Facility; and Stu Taylor, Senior Vice President, Marketing and New Ventures. Before passing the call over to Mick for a review of the quarterly highlights, I’d 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 and projections. Forward-looking statements we may express or implied today are subject to risk and uncertainties which can cause actual results different materially from expectation. Further, some of the information provided refers non-GAAP measures and to know more about these forward looking statements and non-GAAP measures, please see the company's various financial reports, which are available at pembina.com and on both SEDAR and EDGAR. Over to you Mick.

Thanks Scott. Good morning. Looking back, 2017 was a truly a transformative year for Pembina. We had record financial and operating performance completed the largest acquisition in our company's history and placed $4.8 billion of capital project into service. In 2017, we secured approximately $1.2 billion of new growth projects, which further strengthens our service offering within the premier resource place in Western Canada. We also continue to advance our portfolio for future growth opportunities. 2018 is set to be a great year for Pembina as we focus on fully exploiting the assets we have, as well as building out our value chains to provide customers with new premium market for Western Canadian hydrocarbon. I am very proud of the year Pembina had and are excited for what the future holds. I want to thank all of our stakeholders including customers, shareholders, communities and employees for their support during an extraordinary time for Pembina. Scott will now discuss the few highlights from our fourth quarter and annual results.

Thanks Mick. As Mick mentioned, Pembina achieved operational and financial record in both the fourth quarter and full year 2017. Adjusted EBITDA for the fourth quarter was $674 million, an all time quarterly high and a record $1.7 billion for the year as a result of stronger performance across all businesses, including new assets place in the service and increased operating margin from the Veresen acquisition. Adjusted EBITDA was 97% and 43% higher respectively in the comparable period last year. The strong performance resulted in adjusted cash flow per share of $0.99 for the quarter and $3.27 for the year, a 34% and 29% increase over the same period last year. Earnings over the fourth quarter and full year were $445 million and $891 million respectively. This was a 240% and 91% over the same period of the prior year. Now to discuss the results within our five individual businesses including the new Veresen business. Our Conventional Pipeline revenue volume were 862,000 barrels per day for the fourth quarter, a new quarterly record and 757,000 barrels per day in 2017, increases of 35% and 16% respectively. Operating margin in Conventional Pipeline increased by 70% to $201 million for the fourth quarter, as a result of higher revenue and revenue volume for Phase 3 and other assets being placed in the service. For the year, Conventional Pipeline realized operating margin of $656 million, a 33% higher than last year as a result of higher revenue volumes combined with lower operating cost due to geo technical and integrity spending. Next our Gas Services business processed solid quarterly revenue volume of 1.14 Bcf per day in the fourth quarter of 2017 and 1.06 Bcf per day during the year. Revenue volumes were 17% and 26% higher respectively in the comparable period in 2016 due to increase volumes, new assets and the full year contribution of the Kakwa River acquisition. Increased revenue volumes and new assets placed in the service translated into operating margin of $74 million for the fourth quarter, a 23% higher than the comparable period last year. For the year Gas Services recorded operating margin of $276 million, a 42% jump from 2016. Now moving on to Midstream. Operating margin for our Midstream business was $221 million for the fourth quarter and $631 million for 2017, 35% and 22% higher respectively within the same period last year. The increase was primarily driven the start up of RFS3 and the Canadian Diluent Hub at the end of the second quarter of 2017, improved NGL prices in 2017 relative to the prior year and increased crude oil storage opportunities in the first half of 2017. This was partially offset by realized losses on commodity related derivatives during the year and crude oil differentials narrowing in 2017 compared to the previous year. In Oil and Sands business, we continue to see performance in line with previous period as expected with quarterly and full year operating margins totaling $36 million and $144 million, respectively. Finally, with the closing of the Veresen acquisition on October 2, 2017, Pembina added a fifth reporting segment for the fourth quarter of 2017, which included all the assets formerly owned by Veresen. The Veresen assets reported strong 2017 performance, generating proportionately consolidated operating margin of $214 million for the fourth quarter of 2017. Alliance pipeline benefited from high seasonal introducible service demand during the quarter, driven by curtailment and outages on alternative egress options from Western Canada and a wide Chicago AECO price differential. Revenue recognized by Aux Sable a period benefit from the recovery in US export resulting in relatively strong propane plus margin driven by cold weather and wide Chicago AECO price differentials. Additionally, new assets placed in the service by Veresen and Midstream during the second half of 2017 also resulted in increased operating margin relative to the prior period. The Veresen integration has progressed extremely well, as all people and systems have been integrating into day to day operation. A little over four months and we've enjoyed some early wins and remain on track towards achieving our expected synergies at $75 million and $100 million per year. Touching quickly on the impact of US tax reform. In the fourth quarter, we recognized the $70 million deferred tax recovery largely due to the enactment of the Tax Cuts and Jobs Act. Based on our initial review and interpretation of legislation, we expect the impact of lower US tax rate will be in excess of any incremental taxes paid starting in 2020. Pembina remains well positioned for continued growth with one of the strongest balance sheet amongst their peer group. Based on our 2018 adjusted EBITDA guidance of $2.55 billion to $2.75 billion, we expect our 2018 debt to adjusted EBITDA ratio will be approximately 3.8x to 4.1x, which is consistent with our target and supports strong investment grade BBB rating. Additionally, we've recently got approval for $1 billion non revolving term loan which is intended to provide with additional liquidity flexibility and interest cost savings. Finally, we further strengthen our financial position by executing additional hedges to de-risk a significant portion of frac spread margin in our NGL and Midstream business. Excluding our interest Aux Sable we hedged approximately 55% of our frac spread throughput for 2018. I'll now pass the call over to Jason who will provide an update on growth project within our condensate and crude oil value chain.

Thanks Scott. Good morning, everyone. We continue to progress Phase IV and V expansion which will support growth in the Montney deep basin and Duvernay place. Long lead equipment has been ordered for both projects with regulatory environment and environmental approval received for Phase IV and clear and complete with construction underway for Phase V. Both projects are on track to be placed into service in late 2018. In addition to these expansions, we also continue to have the options of further expand capacity in the Fox Creek in the main area to approximately 1.2 million barrels per day by additional pump stations. At our Canadian Diluent Hub, we see increasing condensate deliveries as volumes from Phase III expansion ramp up. In December, 2017 condensate exceeded 145,000 barrels a day and we continue to expect continued growth volume as these volumes increase. I'll now pass the call to Jaret who will provide an update on growth projects within our NGL and natural gas value chain.

Thanks Jason. Good morning, everyone. Yesterday, our Board of Directors approved a construction of fractionation and terminalling facilities which will add approximately 30,000 barrels a day of propane -plus fractionation capacity in Empress, Alberta as part of the company's Empress East NGL system. These facilities will provide the Company with additional NGL volumes and market optionality, as well as enhanced propane supply which could further support our Prince Rupert terminal and proposed PDHPT facility. The total expected cost for this project is approximately $120 million and we expect to have in place late 2020. In November, we were pleased to announce the initial trans of our Duvernay infrastructure under our 20 year development and agreement with Chevron and Kaybob. The total capital cost for the infrastructure is approximately $290 million with an in-service date of mid-to-late 2019. Details engineering for Duvernay II is progressing with some long lead equipment now ordered. Our West Coast propane export strategy continues to progress. We continue consulting with key stakeholders and are working to complete detail engineering to support the facility design and various permit applications expected to be submitted throughout 2018. In terms of our acquired Veresen assets, the first 200 million cubic foot per day processing train of Saturn was placed into service during the fourth quarter. While the second 200 million cubic foot day train was recently placed into service January 23 -28. Both trains were into service ahead of schedule and under budget. The total gas processing capacity at Veresen Midstream is now approximately 700 million cubic feet per day net to Pembina. Continued with Veresen Midstream, in November we announced the approval of the development of the North Central Liquids Hub, which supports the operations of our Midstream partnership in the Montney formation. The estimated capital cost for the project is $150 million net to Pembina with an expected in service date of late 2018. The project currently tracking ahead of schedule and under of budget. Construction is advancing for our first stall ethane storage facility which will have one million barrels of storage capacity. The facility is underpinned by 20 year agreement and is expected to be in place in service late 2018. I'll now pass the call to Stuart Taylor to provide an update on our value chain extension project.

Good morning, everyone. And thanks Jaret. On a proposed PDHPP facility, we continue to progress front end engineering design for the facility. We expect that FEED activities will be completed by late 2018 with a final investment decision to follow. Proposed project will benefit from the joint venture partnership we have with Kuwait Petrochemical Industries Company PIC as it strategically combined the expertise of both companies. We are an experienced operator, builder of large scale infrastructure and aggregator of the largest supply of propane in the Western Canada Sedimentary Basin. Where PIC is a highly experienced global marketer of a variety of petrochemical products including oil field and aromatics. At our proposed Jordan Cove LNG project, we continue to engage with potential customers, remain excited about the fundamental supporting the project. We have committed $135 million in our 2018 capital budget to progress Jordan Cove to a final investment decision pending receipt of required approval and other requirement.

Thanks Stu. In closing, Pembina made transformational stride in 2017. Diversifying our business with a Veresen acquisition and with $4.8 billon of project placed into service. And what was truly an extraordinary year for our company. We are excited for 2018 as our business prospects are positive and supportive and have supported market fundamental. Hydrocarbon liquids prices have been improved, enhancing development economic, supporting increased drilling by our producing customers. At the same time, favorable frac spread continue to drive strong results in our marketing business. The Chicago and AECO gas price differentials are driving strong volumes on the alliance pipeline into the premium Chicago markets. With these strong fundamentals, we remain on track to receive 2018 adjusted EBITDA guidance of $2.55 billion to $2.75 billion. We also continue to have a strong balance sheet, conservative payout ratio and disciplined financial strategy. Our prudent approach allowed us to increase the dividend by 12% in 2017 and consistent with our guardrail to support it entirely by our fee based business. Going forward, we anticipate being able to fund the growing dividend while deploying $1 billion to $2 billion of capital per year without the need to access equity market. As always, we will keep a sharp focus on operating and growing our business within our financial guardrail in a safe reliable manner. In closing, I want to take this opportunity to remind listeners that Pembina is hosting its 2018 Investor Day on Tuesday, May 29 at the Fairmont Royal York Hotel in Toronto. With that we'll wrap things up. Operator, please go ahead and open up the line for questions.

[Operator Instructions] Your first question comes from the line of Jeremy Tonet from JP Morgan. Please go ahead.

Good morning. Congratulations on the big beat there in the quarter. I want to turn to 2018 a bit here and I was wondering if you could help us shape the outlook. It seems if you hedged 65% of your open commodity price exposure, you de-risk good portion of that outlook. And so just wondering if you could help us think about. In the marketing business, is it fair to assume first quarter could approximate the fourth quarter or would you expect something of a step down there? And then just also want to turn towards Phase III kind of the ramp there. Is there a step up in the first quarter? And then is kind of just slight increases across the year or any color you can provide in those topics would be very helpful.

So maybe I'll start. I think overall with the strong fundamentals we are seeing as well as locking in the hedges that we put in, Jeremy, I don't think as you've noticed we are prepared to change our range the 2.55 to 2.75. But I think what it it gives us a high degree of confidence to be able to see within that range. As we look forward to Q1, we did see NGL prices weakened throughout the quarter. A lot of the hedges that we put in place were done in kind of the December timeframe through the beginning of this quarter. So you also have -- you have two issues. One: we have seen prices come down slightly in Q1, as well as of course we've been building inventory through the fourth quarter and January and February. That increases your cost inventory. So I am not sure that the Q1 will be as strong as Q4. But we haven't seen any of the financial numbers yet. I am just going on kind of posted pricing right now. Jason, you want to talk about the ramp up.

Sure. On Phase III I know we've spoken a lot about the fact year-over-year from 2017, 2018, 2019 we see a ramp in our contracted volumes. So that's true for the first quarter of 2018. I think we've explained our contract have a certain amount of firm capacity and then there is take or pay component. So the take or pay component kicked in January. And our results are tracking fairly consistently with our expectations. So we do expect to see the ramp that we expected going in for the first quarter from a revenue volume perspective and then we expect to see volume continue to sort of grow through the years as producers develop their place. We are also still seeing strong demand for capacity on our pipeline systems throughout both Montney and Duvernay play so we continue to have positive outlook for volume as we go forward.

That's helpful. And then the crude marketing just to finish up there; had a notable uptick Q-over-Q. Could you just let's us know how things are looking there I guess?

Q4 definitely benefited from strengthening crude oil prices which led to widening of some differentials. We also had a ramp up in our CDH volumes I think as we discussed previously. So if I look forward to 2018 and you look at kind of where the current price stack is and where current differential are compared to 2017, I think it's safe to say that 2017 a good baseline. It is probably little bit upside from that. So far it just looks like it's getting back to be in a normal year and I would say 2017 was an -- particularly the second half as we discussed often, there were no -- in the market in the second half of the year, 2018 looks more like a normal year again for the crude mainstream business.

That's helpful. Thanks and then just alliance, if you could just update there as far as contracting kind of commercial outlook for extension with the -- the latest thoughts are there?

So like I am sure everyone is aware the open seasons that were run TransCanada. There is still strong demand for gas exploit in the basin. So in terms of Alliance, we are continuing to progress towards formerly launching the open season here in the first quarter and then we are still having good discussion with customers on that expansion and I think right now the timeline for that expansion is the second half of 2020-21 running service date. So nothing is really changed in terms of our expectations there.

Great. And then Jordan Cove real quick, specific connector as far as the outlook for that, it's a slow process but is there anything new to say as far as how that has been progressing?

Nothing new at this point. We are in the mid of our frac application. That is progressing as expected and we are expecting to be receiving initial feedback from FERC and still on target for application to be received in 2018.

And I just add that we are working hard towards our Class III estimate. You guys are aware for the plan we have a fully baked Class II already for the pipe we want to create at that level with sophistication and so we are actively progressing a Class III which is the precision we -- Pembina need to FID projects to this magnitude.

Thank you. And then just real last one. Veresen, synergies you had expected, how much of that has been realized versus might still be left to achieve?

So, again just to clarify that numbers in average over the first several years of operations. So there is some shape to it. We've had as we pointed out some early wins in terms of being able to refinance the Veresen Midstream credit facilities which were pretty meaningful in terms of lower interest cost for 2018 onwards. We also brought over I think as we've mentioned many times the same number of stock that we had modeled in our due diligent process. So we are feeling pretty good about delivering on some of the G&A synergies we model internally. We just finished a bunch of or reorganizations to allow us to capture a bunch of tax synergies. So that's going well as well. And then of course with Veresen, re-contracted it just before we closed the transaction which was an upside that we saw and track that as well. So I think as we mentioned in the conference call, we are feeling pretty good about that target over the first couple of years.

Your next question comes from the line of Rob Hope from Scotiabank. Please go ahead.

Good morning, everyone. Couple of follow ups. Maybe just first on the 2018 outlook. You did mention kind of some tailwinds there being the stronger commodity price environment, asset entering service under budget and faster than expected. Are you seeing any tailwinds developing just versus when you put out that $2.55 billion to $2.75 billion estimate?

What we're prepared to say, I wish I could give you more color, but we're only 45 days into the year, so we're pretty confident that we'll be in a range. Clearly -- when did we make that? Was it August, September? Yes. So it goes back away, I would say from that time we made the guidance, clearly NGL prices are somewhat more robust, Alliance performance is exceeding our expectations as compared to our acquisition model. And piece volumes are really, really building nicely. So we're feeling good about the guidance, and I would say generally more confident than when we made it, I would say, on average.

All right, thank you for that. And then just turning over to Jordan Cove. I guess the project has been in your hands for four months now. It looks like you are focusing on the pipeline but how are customers discussions going on? It would seem that the market is getting a little tighter into the next decade and we do have a rather low AECO price. Have discussions picked up on the customer side there?

Yes. We've continue to meet with the customers we've been talking to for the past little while. The Jordan Cove team is traveling and meeting with all the great customers, the important customers and we are extending some of outreach as well. There is no question that the market is picked up from LNG pricing and the low AECO pricing and other basins are helping with the economic approaching I think the prospective of this project being successful. So everything in recent time has been pointing in the right direction for us.

And then just on that, is the expectation that the buyers could want some regularity clarity so we could see in terms of sequencing some movement on FERC than customer commitments?

We are working with them right now and have some key terms is already executed. There is no question that the FERC application is an important piece of work that has to be completed. We will get some of those agreements will be executed prior to the FERC approval but FERC is a critical item for the regulatory process to proceed and for us to go forward. So I think as we get that at the end of the year that will obviously I think a new wave of conversations and discussions as well.

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

Thank you. A number of my questions have already been answered but maybe we can drill down to some of the puts and takes around your cash tax outlook and maybe effective tax rate with US tax reform? Can you give us a sense of how that might trend this year and beyond?

Sure. So when we look forward to next year, we still see current tax being pretty low just based on all the assets that we placed into service. And then some synergies from the Veresen acquisition. So an outlook for current tax for next year would be or this year I guess I should say would be very consistent with 2017, to somewhere in the neighborhood of call it $40 million to $60 million of current tax expense. From a cash tax perspective we would be somewhere slightly below that. The US tax reform did have us have a $30 million repatriation tax but that's really paid over eight years. So pretty small in the grand scheme of things. So next year we will be calling it $4 million. So pretty minimize overall. We really start to realize lower US tax in 2020. And that's really just a function of our US entities are relatively untaxable in 2018 and 2019. So once we hit full taxability in 2020 in US side that's when we'll start to see some of the lower tax rate kick in.

Okay, thank you. And maybe an update on your outlook for maintenance CapEx. Maybe can you walk us through your operational efficiencies that you expect to achieve longer that kicks on April 1st. should we expect sort of discrete change starting in Q2 and can you describe that?

Hey, Linda. It's Jaret here. Yes, we will be taking over on April 1st, transition is going extremely well. We are in early works. We are going to be getting up there and making offers to all the employees next week and we are extremely excited and taking that over and realizing those synergies. And supplying the high reliability to our customers. While getting into it there is -- I guess that's really all I want to say about that.

Okay.

Once we take it over, Linda, we will understand it significantly more, get the people as part of the Pembina team and start extracting the value as we do too many of our acquisitions and our transition that we do.

Okay. Maybe you can comment on your new propane -plus frac project at Empress. Can you just clarify your expectations of commercial terms for the whole NGL stream? Is it all at this point kind of merchant with propane going to support your LPG and PDH and then the butane plus part of your marking mix or can you comment on the attributes there?

Yes. It's Mick. As you know, Empress is completely commodity exposed business. So there will be no change in commodity exposure for Pembina as a whole. With the redeployment of the project is very cost effective because it redeploys existing vessel on site. And gives us incremental volumes to what we have today but the main thing is it gives us the optionality to leave NGL propane, butane in Alberta versus Sarnia. So we can play that option back and forth and so as you know with our poly propylene aspiration in our West Coast aspiration as well as building pressure from Marcellus that it maybe more economically advantageous to lead products in the West. So this project is about optimizing the value, the molecules and giving us optionality but at the same time bringing incremental barrels. But it is a commodity exposed. It remains a commodity exposed business, let me say that way.

Okay. So just to clarify the volumes will not be additive because they would be fracking existing volumes that would be --

No. They are additive volumes because we can with the expansion process incremental volumes through that facility beyond the capacity we had in Sarnia.

Your next question comes from the line of Robert Catellier from CIBC Capital Market. Please go ahead.

Good morning. I would for you to maybe clarify which projects that you have under development that might be subject to the new approval process and what impact you think it might have and whether it changes your willingness to put development dollars at risk?

Robert, as you know, most of what we do is either in Alberta or in British Columbia, very few cross border projects. So just in this five minutes I really can't think of any projects that would be captured, any material projects that would be captured under the new rule. That's not to say that we are not watching them carefully because what happens to our downstream sector partners ultimately has an impact on us which ultimately has an impact on the basin. So we are watching the development and actively participating in how the intentions of the government get deployed in real world. So we are paying close attention but in terms of our traditional business and on our traditional business model looking forward, there is no material direct impact.

So there is not even Prince Rupert subject to that, to the new process.

No.

Okay. And then I just want to clarify, you've answered this already I think but just to double check. How do you see the recently announced NGL expansion impacting the Alliance re-contracting and expand the possibility, it sounds like you still think that's still be in the market and still think it's a possibility.

You saw the interest in that auction let's call that was tremendous. Keep in mind like Alliance is not a methane pipeline, it's a liquid rich pipeline, a gas pipeline so it's really providing a service beyond methane. So it's a bit dangerous to just kind of compare sands per Mcf straight across the board because we are ultimately transporting a higher value commodity. And the other thing with producers these days with generally with recently lower prices of NGL; they don't necessarily want to build gas plant that can extract more liquid. They want to do minimum liquids recovery and they rather put rich gas into Alliance pipeline than take out all the liquids and transport drag out. So it's signing with Alliance affords you the ability to spend much less capital in the field for certain producers. So you can't quite compare them apples to apples. But we feel I guess the ultimate question is due we feel good about the prospects of the expansion? I would say, yes, we feel very positive about uptick on that expansion. Jason, do you have anything to add?

Yes. I think Mick touched on all the salient points. But I think you also have to remember that really the gas that moves on Alliance is really driven by the liquid productions in Alberta to right so condensate and NGL volumes are really carrying the economic and the gas movement on Alliance really just supports that development. So I think the flexibility around market pricing is little bit stronger on Alliance.

Okay. And just one clarification about the frac spread hedges. I want to make sure the correct interpretation of the 65% hedge level is for calendar 2018 and not just the current winter or NGL year that ends at the end of the March?

That's correct.

Your next question comes from the line of Andrew Kuske from Credit Suisse. Please go ahead.

Thank you. Good morning. This is a question probably for Mick and just if you step back a little bit, you've clearly got a lot of runway in your core Canadian asset exposure in the basin with all the movements are happening from gas and all the talk about more gas coming out and the commitments on the front end NGL. But you also have some projects with big optionality like Jordan Cove, the PDH propane terminal and so when you think about all the opportunity set that you have, how do you also balance the capital that you can put in place with very good fundamentals against just M&A that could be in the marketplace?

The way we start everyday is we look at first our opportunities for brown field. So when we de-bottleneck piece by putting more pumps on expanding asset that's clearly where we are getting the very lucrative kind of 4x to 6x multiple projects. Then we look at greenfield so you mentioned the couples, Jordan Cove and Petrochemicals, those are greenfield and you are not going to get the kind of the multiples you do with brown field, so they come next. And then last generally for the type of quality Pembina pursues for acquisition, you are north of 10x, if you look back we bought stuff 10x to 12x for the best top and then we try to exploit it down to 8x to 10x and hopefully get more brown field opportunities or new platform. So in terms of what we look at everyday acquisitions are the least important. So we look at sweating the assets, feeling the assets we have first de-bottlenecking them, second on greenfield and then lastly on acquisitions.

Okay, that's helpful. And then maybe just following on that with the Veresen assets now in the fold since October 2nd, what additional sweating of those assets do you think you can do in the future and maybe you could break it down into from a commercial standpoint volumetric enhancement and then just cost stripping.

Well, I mean we've already announced the North Central Liquid Hub, so I think that's fantastic example of deploying a bunch of new capital. Those facilities aren't yet full. So there is still work to do fill them. They are performing well. But there is still work to do to fill them. We've spoken off Alliance expansion and it will have small ripple effect into Aux Sable. We are obviously looking at the synergies between our partners at Aux Sable and Alliance, and bridge and ourselves. We are looking at the capabilities. Our companies have that -- we could leverage into the subsidiary company. So we are just really getting started. Let me answer it this way. When we bought Veresen, we had a base case and a development case and we had blue sky case. The base case was our promise to our shareholders, our development case was what we thought we could do, it wasn't guarantee but what's we thought we could do. And the blue sky case was all that work plus Jordan Cove work. We are right now firmly on track for our development case. The blue sky case is possible. We are not ready to say that's the case we are on. But we are firmly on track with our development case. So the business is unfolding as we had hoped and in fact in the near term obviously the result have exceeded -- the near term results through into 2018 look favorable compared to our acquisition model.

And if I may this might be question for Scott and this is more of clarification in your base case synergies of the Veresen transaction. You didn't have significant cost reduction that Alliance baked into that initial synergy numbers. Is that correct?

There is some operational efficiency baked into those numbers. Yes and maybe just a clarifying point as well I should make just on those numbers. I just want to remind everyone that those really were we call it all in cash synergies but not all of that hit EBITDA because there were some pretty significant tax synergies as well as interest savings. So those really are going to hit our adjusted cash flow. So only about half of those synergies were in EBITDA but certainly there were some efficiency across all the assets in those numbers.

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

Good morning. If I can start off just with your self-funding strategy and the statement around $1 billion to $2 billion a year without accessing equity. Just to confirm, does that include keeping the drip off as -- and how does hybrid equity factor into your guidance?

So it definitely includes keeping the drip off and as we sit here today we have no plan to issue hybrid equity. So it's truly cash flow after dividend. And debt to fund $1 billion to $2 billion.

Okay. So in some ways adding perhaps or trust notes or senior sub debt could actually scale that number a little bit higher?

Potentially but that's currently how we think about, Robert. We think we can fund the capital with just like I said cash flow to debt.

Okay. Fair enough. And then just on the leverage metrics of 3.84 to 4.1 for 2018. Just want to make sure I want to know what's in the calculation. So on the EBITDA, I assume, is that your adjusted EBITDA number? And then in terms of the debt side, does it include all of the off-balance-sheet debt you took on from Veresen?

Correct. It's proportionally consolidated. So it's proportionally consolidated debt to proportionally consolidated EBITDA.

Perfect. Just turning to Empress. Can you talk about where the attraction premiums for Empress are sitting? Call it may be some color on where the 2017 gas year was versus the gas year we're now in. And with the new contracting on the mainline, are you seeing a benefit in terms of volumes coming through Empress?

So I say 2018 generally is in line with 2017. As you know, the gas year was done in October. So we -- I wouldn't say that we are seeing the benefit of all the volumes going through their driving down extraction premium that may manifest itself in 2019 onwards. But the gas year has already been contacted back in October.

Okay, so pricing -- sorry, go ahead.

I would just that with ECPL expansion, obviously, we have more and more confidence with throughput at Empress and that's clearly factored in FID being new capital project there. We see border flows starting to -- well I mean they were what as low as in the 3 Bcf per day few years ago and they are creeping up and we see them way, way higher looking forward. So that was a factor in the FID of the new frac.

Got it. So pricing on the extraction premiums are about the same. But kind of as you got through Q4 and what you're seeing right now, we've seen mainline volumes up, call it about half a day. Are you seeing some sort of uptick as well in volumes through Empress and therefore liquids volumes?

We were contracted, Robert. We already told so incremental volumes going through Empress didn't really benefit us in the short term. We were already operating in near capacity.

Got it. And then just last on the NGL hedges. Have you hedged both sides on the frac, both the NGLs and the underline gas?

Absolutely, yes.

We always do, Robert.

We decide to pick number so we use throughput versus sale but it really is throughput and the sales.

Your next question comes from the line of [Indiscernible] from Industrial Alliance. Please go ahead.

Good morning. I just have two questions today. The first is, of the funding commitment for up to $5 billion of new infrastructure Veresen Midstream has with the Cutbank Ridge partnership. How much has been spent today?

I don't -- do we -- just hang on, do we announce -- do we disclose that? I don't think I am sorry. We can get your name. We can get back to you. We don't know about something that we disclosed this time. So apologies. It could be governed under the confidentiality agreement and I don't know, no one in the room here looks like they know that. So we are going to respectfully not answer that question until we know whether the confidentiality agreement allows us to disclose that.

Okay. No problem. My second question is in reference to the ethane gathering system and the competition bureau. Where we at with that process and do you expect that to have an impact moving forward?

There is nothing new to report there. What we can say is -- what we just reiterate I mean that even if something were to occur which our position is that nothing will occur. It is not a material part of our business particularly now that -- let's say in the worst and unlikely case we had to demonetize that asset given it has been re-contracted we would get full value for that asset. But even in that case it's not a material part of our EBITDA. It is -- we like the way it looks on a map because it connects all of our infrastructure. And we definitely want to keep it. We expect to keep it. But if we had to, again in the unlikely event we had to monetize that asset for some reason it wouldn't have a material impact on our business.

There are no further questions at this. I turn the call back over to management.

Well, thanks everybody. Again just reiterating our appreciation for the strong support from all of our stakeholders group. We are looking very much forward to 2018. And exploiting the assets we have and building up our new platform. We are having a lot of fund. And thanks again for your support. Have a great weekend.

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