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Pembina Pipeline Corp
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Good morning, my name is Zafra, 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. [Operator Instructions]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, Pipelines; and Jaret Sprott, Senior Vice President and Chief Operating Officer, Facilities; 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 may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments and projections. Forward-looking statements we may express or imply today are subject to risk and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn 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 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 projects into service. In 2017, we secured approximately $1.2 billion of new growth projects, which further strengthens our service offering within the premier resource plays in Western Canada. We also continued to advance our portfolio of future growth opportunities. 2018 is said to be a great year for Pembina as we focus on fully exploiting the assets we have as well as building out our value chain to provide our customers with new premium markets for Western Canadian hydrocarbon. I'm very proud of the year Pembina had, and I'm 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 records 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 placed into 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% increase over the same periods of the prior year. Now to discuss the results within our 5 individual businesses, including the new Veresen business.Our Conventional Pipeline revenue volumes 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 Pipelines increased by 70% to $201 million for the fourth quarter as a result of higher revenue and [ net ] new volumes from Phase III and other assets being placed into service. For the year, Conventional Pipelines realized operating margin of $656 million, a 33% higher than last year as a result of higher revenue volumes combined with lower operating costs due to geotechnical and integrity spending.Next, our Gas Services business processed solid quarterly revenue volumes 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 periods in 2016 due to increased volumes from new assets and the full year contribution of the Kakwa River acquisition. Increased revenue volumes from new assets placed into service translated to an 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 onto 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 periods last year. The increase was primarily driven by the startup of RFS III 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 our Oil Sands business, we continued to see performance in line with previous periods as expected, with quarterly and full year operating margin 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 of the assets formerly owned by Veresen. The Veresen assets reported strong 2017 performance, generating proportionally consolidated operating margin of $214 million for the fourth quarter of 2017. Alliance Pipeline benefited from high seasonal interruptible service demand during the quarter, driven by curtailments and outages on alternative egress options from Western Canada and a wide Chicago-AECO price differential. Revenue recognized by Aux Sable during the period benefit from a recovery in U.S. exports, resulting in relatively strong propane-plus margins, driven by cold weather and a wide Chicago-AECO price differential. Additionally, new assets placed into service by Veresen 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 integrated into our day-to-day operations. A little over 4 months in, we've enjoyed some early wins and remain on track towards achieving our expected synergies at $75 million to $100 million per year.Touching quickly on the impact of U.S. tax reform. In the fourth quarter, we recognized a $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 the legislation, we expect the impact of lower U.S. 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 sheets amongst their peers. 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 a strong investment grade, BBB rating. Additionally, we recently got approval for $1 billion non-revolving term loan, which is intended to provide us with additional liquidity, flexibility and interest cost savings. Finally, we've further strengthened our financial position by executing additional hedges to derisk a significant portion of the frac-spread margin in our NGL Midstream business. Excluding our interest in Aux Sable, we've hedged approximately 65% of our frac spread throughput for 2018.I will now pass the call over to Jason, who will provide an update on growth projects within our condensate and crude oil value chain.
Thanks, Scott. Good morning, everyone. We continue to progress the Phase IV and V expansions, which will support growth in the Montney, Deep Basin and Duvernay plays. Long-lead equipment has been ordered for both projects with regulatory environment -- and environmental approvals received for Phase IV and clearing 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 option to further expand capacity in the Fox Creek and Namao area to approximately 1.2 million barrels per day by adding additional pump station. At our Canadian Diluent Hub, we see increasing condensate deliveries with volumes from our Phase III expansion ramp up. In December 2017, condensate receipts exceeded 145,000 barrels a day, and we continue to expect continued growth volume as Peace volumes increase.I will 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 the construction of fractionation and terminaling 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 an enhanced propane supply, which could further support our Prince Rupert terminal and proposed PDH/PP facilities. The total expected cost for this project is approximately $120 million, and we expect to have them placed late 2020. In November, we were pleased to announce the initial tranche of our Duvernay infrastructure under our 20-year development and agreement with Chevron and KUFPEC. The total capital cost for the infrastructure is approximately $290 million with an in-service date of mid-to-late 2019. Detailed 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 detailed 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, 2018. 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. Continuing with Veresen Midstream, in November, we announced the approval of development of the North Central Liquids Hub, which supports the operation of our Midstream partnership in the Montney formation. The estimated capital cost for the project is a $150 million net to Pembina with an expected in-service date of late 2018. The project is currently tracking ahead of schedule and under budget. Construction is advancing for our Burstall Ethane Storage facility, which will have 1 million barrels of storage capacity. The facility is underpinned by a 20-year agreement and is expected to be in place in-service late 2018.I will now pass the call to Stu to provide an update on our value chain extension projects.
Good morning, everyone, and thanks, Jaret. On our proposed PDH/PP facility, we continue to progress Front End Engineering Design for the facility. We expect that, that FEED activities will be completed by late 2018, with the final investment decision to follow. Proposed project will benefit from the joint venture partnership we have with Kuwait's Petrochemical Industries Company, PIC, as it strategically combines the expertise of both companies. We're an experienced operator, builder of large-scale infrastructure and aggregator of large -- of the largest supply of propane in the Western Canada Sedimentary Basin, whereas, PIC is a highly experienced global marketer of a variety of petrochemical products, including olefins and aromatics. At our proposed Jordan Cove LNG project, we continue to engage with potential customers, remain excited about the fundamentals supporting the project. We have committed $135 million in our 2018 capital budget to progress Jordan Cove to a final investment decision pending the receipt of required approvals and other requirements.
Thanks, Stu. In closing, Pembina made transformational strides in 2017, diversifying our business with the Veresen acquisition and with $4.8 billion of projects placed into service, and what was truly an extraordinary year for our company. We're excited for 2018, as our business prospects are positive and supportive -- and have supportive market fundamentals. Hydrocarbon liquids prices have improved enhancing development economics and supporting increased drilling by our producing customers. At the same time, favorable frac spreads 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 market. With these strong fundamentals, we remain on track to achieve 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 guardrails is supported entirely by our FEED-based business. Going forward, we anticipate being able to fund a growing dividend, while deploying $1 billion to $2 billion of capital per year without the need to access equity markets. As always, we'll keep a sharp focus on operating and growing our business within our financial guardrails 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 JPMorgan.
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've derisked a good portion of that outlook. And so I was just wondering if you could help us think about that 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 a ramp-up 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 on those topics would be very helpful.
So maybe, I'll start. I think, overall, with the strong fundamentals we're seeing as well as locking in the hedges that we put in, Jeremy, I don't think, as you've noticed we're prepared to change our range to $2.55 billion to $2.75 billion. But I think what it does is give us a high degree of confidence to be able to be within that range. As we look forward to Q1, we did see NGL prices weaken throughout the quarter. A lot of the hedges that we put in place were done in kind of December timeframe through the beginning of this quarter. So you also have 2 issues. One, we've seen prices come down slightly in Q1 as well as, of course, as we've been building inventory through January and -- sorry, through the fourth quarter and January and February, that increases your cost inventory. So I'm not sure that Q1 will be as strong as Q4, but we haven't seen any of the financial numbers yet. I'm just going off kind of post the pricings right now. Jason, do you want to talk about the ramp-up?
Sure, on Phase III, I know we've spoken a lot about the fact that year-over-year from '17, '18, '19 we see a ramp in our contracted volumes. So that's true for the first quarter of 2018. As -- I think we've explained our contracts have a certain amount of firm capacity and then there is a take-or-pay component. So the take-or-pay component kicked in in January, and our results are tracking fairly consistently with our expectations. So we do expect to see the ramp that we expected going into the first quarter from a revenue volume perspective. And then we expect to see volumes continue to sort of grow through the year as producers develop their plays. We're also still seeing strong demand for capacity on our pipeline systems throughout both the Montney and Duvernay plays. So we continue to have a positive outlook for volumes 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 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've discussed previously. So if I look forward to 2018 and you look at kind of where the current price deck is and where current differentials are compared to 2017, I think safe to say that 2017 is a good baseline and there's probably a little bit of upside from that.
Yes. So far, it just looks like it's getting back to being a normal year, and I would say 2017 was -- particularly the second half as we've discussed often, there were no [ arbs ] in the market in the second half of the year. 2018 looks more like a normal year again for the crude Midstream business.
That's helpful. And then just Alliance, if you could just update us there as far as contracting kind of commercial outlook for expansions, what the latest thoughts are there?
So I'm sure everyone's aware of the open seasons that were run by TransCanada. There is still strong demand for gas export in the basin. So in terms of Alliance, we're continuing to progress towards formally launching the open season here in the first quarter. And then we're still having good discussion with customers on that expansion, and I think right now the timeline for that expansion is the second half of 2021 for in-service dates. So nothing's really changed in terms of our expectations there.
Great. And then Jordan Cove, real quick, Pacific Connector thus 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're in the midst of our FERC application. That is progressing as expected. And we're expecting to be receiving initial feedback from FERC and are still on target for application to be received in 2018.
And I'd just add that we're working hard towards our Class 3 estimate. You guys are aware for the plant, we have a fully baked Class 2 already. For the pipe, we weren't quite at that level of sophistication. And so we are actively progressing the Class 3, which is the precision we -- Pembina needs to FID projects of this magnitude.
And then just real last one. Veresen, synergies you expected, how much of that has been realized versus might still be left to achieve?
So again, just to clarify that number is an 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 was pretty meaningful in terms of lower interest costs for 2018 onwards. We also brought over, I think as we've mentioned many times the same number of stocks that we had modeled in our due diligence process, so we're feeling pretty good about delivering on some of the G&A synergies we modeled internally. We've just finished a bunch of our reorganization to allow us to capture a bunch of the tax synergy, so that's going well as well. And then, of course, with Veresen recontracted AEGS just before we closed the transaction which was some upside that we stopped the transaction as well. So I think as we mentioned in the conference call, we're feeling pretty good about that target over the first couple of years.
Your next question comes from the line of Rob Hope from Scotiabank.
A couple of follow-ups. Maybe just first on the 2018 outlook, you did mentioned kind of some tailwinds there being the stronger commodity price environment, assets 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 the range. Clearly, I mean, that -- when did we make that? Was it August, September?
Yes.
Yes, so it goes back away. I would say from the time we made the guidance, clearly NGL prices are somewhat more robust. The Alliance performance is exceeding our expectations as compared to our acquisition model. And Peace 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.
And then just turning over to Jordan Cove. I guess, the project has been in your hands for 4 months now. It looks like you're focusing on the pipeline. But how are customer discussions going on? It would seem that the market's 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 continued 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 right customers, the important customers. And we're extending some of our outreach as well. There's no question that the market has picked up from LNG pricing and the low AECO pricing, and other basins are helping with the economics of the project and I think the prospective of this project being successful. So everything is -- in recent times, has been pointing in the right direction for us.
And then just on that, is the expectation that the buyers could want some regulatory clarity? So we could see, in terms of sequencing, some movement on FERC than customer commitments?
We're working with them right now and have some key term sheets already executed. There's 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'll, obviously, I think the -- a new wave of conversations and discussions as well.
Your next question comes from the line of Linda Ezergailis from TD Securities.
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 U.S. 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've 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. So 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 U.S. tax reform did have a $30 million repatriation tax but that's really paid over 8 years. So pretty small in the grand scheme of things. So next year will be, call it, $4 million.[ Audio Gap ]So pretty naturally just a function of our U.S. entities are relatively untaxable in 2018 and 2019. So once we hit full taxability in 2020 on the U.S. side, that's when we'll start to see some of the lower tax rate kick in.
Okay. And maybe an update on your outlook for maintenance -- oh, sorry, you don't have maintenance CapEx. Maybe can you walk us through your operational efficiencies that you expect to achieve at Younger that kicks in on April 1? Should we expect some sort of discrete change starting in Q2 and can you describe that?
Linda. Yes, Jaret here. Yes, we'll be taking over on April 1. Transitions going extremely well, we're in the early works. We're going to be getting up there and making offers to all the employees next week. And we're extremely excited in taking that over and realizing those synergies and supplying the high reliability to our customers. What I'm 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'll understand it'll significantly more get the people as part of the Pembina team and start extracting the value as we do through many of our acquisitions and our transitions that we do.
Okay. Maybe you can comment on your new propane-plus frac project at Empress. Can you just clarify your expectation 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 marketing mix? Or can you comment on the attributes there?
Yes, it's Mick. As you know, Empress is completely a commodity-exposed business. So there'll be no change in commodity exposure for Pembina as a whole. What the redeployment of the -- the project is very cost effective because it redeploys existing vessels on site and gives us incremental volumes to what we have today. But the main thing it gives us is the optionality to leave NGLs, propane, butane in Alberta versus Sarnia, so we can play that option back and forth. And so as you know, with our polypropylene aspirations and our West Coast aspirations as well as building pressure from Marcellus that -- it may be more economically advantageous to leave products in the West. So this project is about optimizing the value of 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 it that way.
Okay, so just to clarify the volumes would not be additive because they would be fracking existing volumes that would be going to...
No, there 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 Markets.
I'd like 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 5 minutes, I really can't think of any projects that would be captured -- any material projects that would be captured under the new rules. That's not to say that we're 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're watching the developments and actively participating in how the intentions of the government get deployed in real world. So we're 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's -- not even Prince Rupert's subject to that?
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 NGTL expansion impacting Alliance recontracting and expansion possibility? It sounds like you still think that will still be in the market and still think it's a possibility.
You saw the interest in that auction, let's call it that, was tremendous. Keep in mind like Alliance is not a methane pipeline. It's a liquids-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 cents per Mcf straight across the board because we're ultimately transporting a higher-value commodity. And the other thing with producers these days with generally, which -- recently lower prices of NGLs, they don't necessarily want to build gas plants that can extract more liquids. They want to do minimum liquids recovery and they'd rather put rich gas into Alliance pipeline than take out all the liquids and transport dry gas. So it -- signing with Alliance affords you the ability to spend much less capital in the field for certain producers. So it -- you can't quite compare them apples-to-apples. But we feel, I guess, the ultimate question is do we feel good about the prospects of the expansion? I would say, yes, we feel very positive about uptake 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 liquids production in Alberta too, right? So the condensate and NGL volumes are really carrying the economics and the gas movements on Alliance really just support those developments. So I think the flexibility around market pricing is a 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 in -- at the end of March?
That's correct. It's for the year.
Your next question comes from the line of Andrew Kuske from Crédit Suisse.
The question is probably for Mick, and just to 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 that are happening from gas and all the talk about more gas coming out and the commitments on NGPL. But you also have some projects of 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 every day is, we look at, first, our opportunities for Brownfield. So when we debottleneck Peace Pipe by putting more pumps on or expand an asset, that's clearly where we're getting the very lucrative kind of 4x to 6x multiple projects. Then we look at Greenfield. So you've mentioned a couple, Jordan Cove and Petrochemical, those are greenfield and you're not going to get the kind of multiples you do with Brownfield, so they come next. And then last, generally, for the type of quality Pembina pursues for acquisitions, you're north of 10x. If you look back, we've bought stuff 10x to 12x for the best stuff, and then we try to exploit it down to 8x to 10x, and hopefully get more Brownfield opportunities or a new platform. So in terms of what we look at, every day acquisitions are the least important. So we look at sweating the assets, filling the assets we have. First, debottlenecking 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 2. 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 enhancements and then just cost stripping?
Well, I mean, we've already announced North Central Liquids Hub. So I think that's a fantastic example of deploying a bunch of new capital. Those facilities aren't yet full, so there's still work to do to fill them. They're performing well, but there's still work to do to fill them. We've spoken of Alliance expansion, it'll have a small ripple effect into Aux Sable. We are obviously looking at the synergies between our partners at Aux Sable and Alliance, Enbridge and ourselves. We're looking at the capabilities our companies have that we could leverage into the subsidiary company. So we're just really getting started. Let me answer it this way. When we bought Veresen, we had a base case, had a development case, then we had a 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 a guarantee but was what 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're not ready to say that's the case we're on. But we're 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 results have exceeded -- the near-term results through into 2018 look favorable compared to our acquisition model.
And if I may, this might be a question for Scott and this is more of a clarification in your base case synergies. After the Veresen transaction, you didn't have significant cost reductions that Alliance baked into that initial synergy number, is that correct?
There was some operational efficiencies baked into those numbers, yes. And then maybe just a clarifying point as well that I should make just on those numbers. I just want to remind everyone that those really were, we'll call it, all in cash synergies, so not all of that hit EBITDA because there was 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 was some efficiencies across all the assets in those numbers.
[Operator Instructions] Your next question comes from the line of Robert Kwan from RBC Capital Markets.
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 plans to issue hybrid equity. So it's truly cash flow after dividends and debt to fund the $1 billion to $2 billion.
Okay. So in some ways adding perhaps or trust notes or senior subdebt could actually scale that number a little bit higher?
Potentially, but that's not currently how we think about it, Robert. We think we could fund the capital with just, like I said, cash flow or debt.
Fair enough. And then just on the leverage metrics of 3.8x to 4.1x for 2018. Just want to make sure I 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 Veresen?
Correct. It's proportionally consolidated. So it's proportionally consolidated debt to proportionately consolidated EBITDA.
Perfect. Just turning to Empress. Can you talk about where the attraction premiums for Empress are sitting? Call it maybe 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'd 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're seeing the benefit of all the volume going through there driving down extraction premiums, that may manifest itself in 2019 onwards. But the gas year has already been contracted back in October.
Okay, so pricing... I'm sorry, go ahead.
I would just add that we -- with the [ ECPL ] expansion, obviously, we have more and more confidence with throughput at Empress. And that was clearly a factor in FID-ing our new capital project where we see border flows starting to -- I mean, they were what, as low as in the 3 bcf today a few years ago, and they're 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 that are -- kind of as you got through Q4, and what you're seeing right now, we've seen mainline volumes up, call it, about half [ Va ] day. Are you seeing some sort of uptick as well in volumes through Empress and therefore liquids volumes?
We were contracted, Robert, so we are already full. So incremental volumes going through Empress didn't really benefit us in the short term because we were already operating at 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 underlying gas?
Absolutely. Yes.
We always do, Robert. We always do.
We just had to pick a number, so we use throughput versus sales, but it really is throughput and sales.
Your next question comes from the line of Amber Brown from Industrial Alliance.
I just have 2 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 to date?
I don't -- do we, just hang on -- do we announce -- do we disclose that? I don't think -- I'm sorry, if we can get your name, we can get back to you. We don't know if that's something that we disclose at this time. So apologies.
Okay, no problem.
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're 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 are we at with that process? And do you expect that to have an impact moving forward?
There is no -- nothing new to report there. What I -- what we can say, what we -- just to reiterate, I mean, that, 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 monetize that asset. Given it's been recontracted, 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 the 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 time. I turn the call back over to management.
Well thanks, everybody. Again, just reiterating our appreciation for the strong support from all of our stakeholder groups. We are looking very much forward to 2018 and exploiting the assets we have and building up our new platform. We're having a lot of fun. And thanks again for all your support. Have a great weekend.
This concludes today's conference call. You may now disconnect.