Welcome to the Enbridge Inc. Fourth Quarter 2018 Financial Results Conference Call. My name is Liz and I will be your operator for today. At this time, all participants are on a listen-only mode. Following the presentation, we will conduct a question and answer session for the investment community. During the question and answer session, if you have a question, please press star one on your touch-tone phone. Please note that this conference is being recorded. I will now turn the call over to Jonathan Gould, Director, Investor Relations. Jonathan, you may begin.
Great. Thank you, Liz. Good morning. Welcome to the Enbridge Inc. Fourth Quarter 2018 Earnings Call. With me this morning are Al Monaco, President and CEO, John Whelen, Chief Financial Officer, Allen Capps, Chief Accounting Officer, Guy Jarvis, President, Liquids Pipelines, and Bill Yardley, President, Gas Transmission and Midstream. As per usual, this call is webcast. I encourage those listening on the phone to follow along online with the supporting slides. A replay and podcast of the call will be available later today. A transcript will be posted to the website shortly thereafter. In terms of Q&A, we'll prioritize calls from the investment community only. If you're a member of the media, please direct your inquiries to our communications team, who will be happy to respond directly.
We're again going to target keeping the call to roughly an hour and may not be able to get to everybody. Please try to limit your questions to one and a follow-up as necessary. As always, our investor relations team is available for your more detailed follow-ups or modeling questions afterwards. On to slide two, where I'll remind you that we will be referring to forward-looking information on today's call. By its nature, this information contains forecast assumptions and expectations about future outcomes, which are subject to the risks and uncertainties outlined here and discussed more fully in our public disclosure filings. We'll also be referring to the non-GAAP measures summarized below. With that, I'll now turn the call over to Al Monaco.
Thanks, Jonathan. Good morning, everyone. We finished the year strong with another very good quarter. With that, 2018 is now in the books. With a number of other accomplishments last year, we're now set up very well for the future. This morning, I'll recap the great progress on our priorities, followed by a business update. John Whelen is here today. He's lost his voice over the last couple of days. Allen Capps will review the results and financial outlook later on. I'll wrap up with our priorities heading into 2019 and beyond. Slide four is the checklist that we established for ourselves at the beginning of last year after completing the integration of Spectra. A major priority, deliver strong results for the first full year after the deal. Another was to move to a pure pipeline utility business model, because that's what we're best at.
That meant selling non-core assets and accelerating de-leveraging. Another objective was to streamline the business, drive efficiency, and simplify our structure. There was a big focus on executing our secured capital program, which is the key to growing cash flow, of course. At the same time, the goal is to replenish secured growth beyond 2020. That's what we set out to do. Let's look at the scorecard now, starting with the financial results on slide five . Our business no doubt fired on all cylinders last year, and we delivered record numbers. EBITDA, as you saw, came in at almost CAD 13 billion and distributable cash flow at CAD 7.6 billion. That translates to CAD 4.42 in DCF per share, which is at the high end of the 2018 guidance range of CAD 4.15-CAD 4.45. That's a 20% increase year-over-year.
Q4 came in at CAD 1.03 per share, a very good result. Same strong story on adjusted earnings at CAD 0.65 a share for the quarter and CAD 2.65 for the year. The things that really stood out here, we think, were great operating performance, new projects coming online, and continued synergy capture from the Spectra deal. Our 2018 dividend coverage came in at about 1.65 x, very strong as well. We increased the dividend another 10% to CAD 2.95 per share for 2019. Allen will get into more detail on the results. Turning to slide six and the asset sales. We initially targeted CAD 3 billion last year, and we hit that target by May. As we went through it became very clear there was a big appetite out there for assets, so we capitalized and ended up executing almost CAD 8 billion for the year.
The valuations we got confirmed these were excellent capital allocation moves for us for non-core assets. The multiples also highlight how valuable our core pipe and utility assets are today. Bigger picture, these transactions got us to a pure-play utility pipeline model we were targeting in just one year. Their size also significantly accelerated de-leveraging and gave us additional financial flexibility. On that note, as you see on slide seven , debt to EBITDA came down to 4.7 x at year-end, well below the original 5x target we set for 2018 and down markedly from around six in 2016. We also reset our long-term leverage target range to 4.5x to comfortably below 5x . Actually, the plan, as you see here, shows us coming down below that range to about 4.3x after Line 3 is completed.
As you saw, Moody's just upgraded us and maintained a positive outlook. If you look at what they said, the upgrade reflects the strategic actions that we've taken. Equally important, faster deleveraging allowed us to shut off the DRIP sooner, and that was the last step in moving to a fully self-funded capital model. On to slide eight. Another heavy lift was the rolling up of our four sponsored vehicles, as they simply, in our view, no longer provided the benefit that they once did. We now have all of our core assets under the Enbridge roof and have eliminated complexity, so we can better highlight the transparency of our cash flows to investors. There are also a number of other tangible benefits that we've been talking about that you see here, like strengthening our credit and extending our non-taxable horizon.
Bottom line, the simpler structure is a big plus and allows us to focus energy on the core businesses as we should. On the next slide, at our Enbridge Day, we announced CAD 1.8 billion of new projects in both Liquids and Gas Transmission . You can see how these are all within our existing footprints and fit our low-risk value proposition very well. We think a key one is the Gray Oak Pipeline out of the Permian, which fits nicely with our strategy to build a network in the U.S. Gulf Coast. What we really like about it is the solid upstream fundamentals and how it connects, though, to the highest value markets downstream, especially global exports through our Texas COLT offshore VLCC loading facility, which is now in development. On the gas side, we announced several smaller expansions and extensions, which leverage the existing systems. On to slide 10.
We brought over CAD 7 billion of projects into service last year, and our remaining secured inventory now stands at CAD 16 billion. That actually includes a recently secured regulated electricity transmission investment in Northern Ontario. In fact, earlier this week, we received the leave to construct from the OEB for the East-West Tie Line, which will add much-needed capacity between Wawa and Thunder Bay in Northeast Ontario. It's a full cost of service-type project with our share around CAD 200 million, and we're targeting in-service in 2021. Incidentally, we have Indigenous partners here who will also become partners in the project once we go into service. We also agreed to acquire a recently constructed and fully contracted generation gas pipeline. It's a smallish but strategic bolt-on that allows us to capitalize on the attractive and growing Toledo industrial and power gen corridor.
It provides a great outlook through a future connection to NEXUS. In the last two months, we've added another CAD 300 million in growth capital to the CAD 1.8 billion we announced at Enbridge Day. Both of these projects fit very nicely within the pure pipeline utility business model and demonstrate again the solid expansion and extension of the franchise. As you can see in the table, the secured projects are well diversified by size, geography, and business. That's the model going forward, very manageable, relatively low risk, singles, and doubles in the future. Switching gears now to the business update, starting with the liquids mainline on slide 11. We saw a record Q4 mainline throughput, and that's actually continuing on into January and February. Since 2015, we added 450,000 bpd of capacity, and Guy and his team are working on a number of additional near-term and longer-term enhancements.
From our customer standpoint, the sooner the better. The most immediate is a 50,000 bpd-100,000 bpd additional opportunity to move Alberta barrels by mid-year, and that's obviously much needed in a curtailed production environment in Alberta. Because of the reliability and optionality that the mainline provides, there's very strong shipper interest in our priority access contract offering, and we've talked about the key features of that, which are seen here on this slide. Discussions with the industry are moving along very well, and we expect to launch in open season sometime in Q2. If all goes well, we should be in a position to file with the NEB in the second half of the year. The plan is for the priority access structure that we're coming up with here to take effect when the current CTS agreement expires in mid-2021.
To complement that, we're seeking additional commitments on Flanagan South and Seaway, which would underpin further expansion on those systems. On to slide 12 and a Line 3 update. This project has obviously got lots of interest. Let's first provide some context because the project is unique in that it's not a greenfield build. Rather, it's a replacement of a critical line that simply needs to be done. Just like we would replace aging infrastructure in our economy like bridges, railway lines, and transmission lines. The replacement is in everybody's interest, from landowners, communities, and Indigenous and tribal nations. These groups along the entire right of way support replacement and want us to get it done. That was the conclusion reached in Minnesota after a 43-month regulatory review, one of the best and most thorough that we've seen.
The project also helps keep energy costs and gas pump prices low, avoids crude by rail, and is going to boost economic growth and create jobs. Local businesses have been planning for this for a long time, and they're ready to go. Line 3 will generate millions in annual property tax revenue to support services that counties and municipalities are looking forward to and are planning to have. Clearly, this pipeline is critical, and it has massive support. With PUC approval, we've reached the final permitting and construction phase of the project, with regulators in all jurisdictions having now approved it's full steam ahead on the remaining project execution phases. Now in Canada, actually, we have all 1,100 km of pipe welded up in the ground in backfill. By the way, again, a great partnership here with First Nations and Métis groups.
We're proud of what we've done with them in creating that partnership, it's going to serve, we think, as a great model in the future. There's still a lot of work to do in Canada on pump stations and terminal tie-ins, we expect to have all of that complete and the pipe ready to line fill by the beginning of June. In Wisconsin, the pipe was already replaced and was put into service last year. In North Dakota, we've tied in the border crossing already, and there's about 15 mi yet to construct, likely this summer. Getting back to Minnesota, as I mentioned, we are now in the permitting phase, I'll take a bit more time on that one on the next slide.
First of all, the nearly four-year process here leading up to final regulatory approval was based on a very intensive and comprehensive study that built a robust record of environmental review and public input that's going to support the permitting process we're in right now. The MPUC approval of the certificate of need and route were the most significant milestones by far. The PUC decisions were again reinforced in Q4 with written orders and the denial of petitions for reconsideration. Much of the work to finalize the conditions on the certificate of need has now been completed with the MPUC's written order on these issued last month. Before I get to the permitting update, let me provide some color and our perspective on the process and some of the discussion we've been hearing.
As you know, it's common in this environment for regulatory decisions to be challenged, which is why the thoroughness of the regulatory process is so important to everyone, including us. As an example, the petitions for reconsideration related to the latest PUC order that were filed by several parties, including the Department of Commerce. Although we certainly don't agree with their views, and neither, by the way, did the PUC or the ALJ in this case, we're not surprised by the filing given their previous petition. Actually, we all agree that everybody should be heard throughout the process. The other important point is that the petitions or appeals shouldn't interfere with the timing of the permitting process. That's been our view for a while, and we've confirmed it with the state and the agencies.
In fact, the agencies have been working on the permits through the prior challenges, this is really no different. Here's the status on the permitting. Recall that we submitted all of the federal, state, and local permits, the applications were deemed complete by the various agencies. We've been working with agency staff quite diligently over the last few months, getting prepared. More recently, we've been in discussions with the agency leadership now that they're in place on process and timelines. As to timing, we don't have a final estimate for completion of permits, but it's worth noting that we have flexibility on the construction start date. Once permits are granted, we'll optimize construction and we don't expect seasonal windows to affect our in-service timing this year.
With timely approvals, we still expect to be able to bring the line into service before the end of the year. The project is obviously important to everybody, so we'll continue to provide information on a regular basis as we progress through the final stages. Now on to slide 14 and the update on Gas Transmission. 2018 was a strong year for system utilization, Texas Eastern and Algonquin in particular, were again in very high demand. We also reached peak deliveries on almost all of our systems. Proof of that, Bill and his team were able to recontract over 90% of the revenue that was up for renewal on the major pipes. It's never been clear that we need additional natural gas infrastructure, and nowhere is that more evident than in the U.S. Northeast.
We've shown a couple of charts here on the slide of gas and electricity prices, which as you see, continue to spike with consumers paying through the nose for higher-priced, lower-reliability peaking supply from oil generation and foreign LNG imports. This is actually an unbelievable irony when the Marcellus is sitting right next door to this market. We'll continue to work with regulators and local politicians to bring forward solutions to this problem. Over to slide 15. On the regulatory front, tax reform and the need to modernize our systems, that's really causing us to file more frequent rate cases. That allows us to rebase and recover the capital we've invested over time and as we execute on modernization that needs to be done. We filed our Texas Eastern rate case with the FERC last November, we're progressing that with our customers.
With ongoing modernization capital, we'll likely be filing full rate cases on Algonquin and East Tennessee as well. To slide 16 and a few comments on the utility business. Operationally, this business is performing tremendously well. With the most recent cold snap in Ontario, utility had near record gas sendout for a couple of those days at 7 billion cubic feet. If there was any doubt about the importance of energy infrastructure, the recent cold snap should address that. We're also seeing record storage draws at Dawn, and remember, post Spectra, we now have almost 270 billion cubic feet of capacity in the region. As of January 1, Cynthia and her team have brought our two utilities into one single operation, and there's a good opportunity here to eliminate duplication, while at the same time maintaining our strong standards for safety and service.
We expect to achieve in the 100 basis point range in excess of the allowed return over the five-year incentive term, and hopefully we can do better, plus the ongoing inherent growth in the rate base through steady customer adds. With that, let me now hand it over to Allen for the financial update.
Well, thanks, Al, and good morning, everyone. With the buy-in of our four sponsored vehicles, we have now brought virtually all of our assets under the umbrella of a single publicly traded entity. My run-through of the numbers this morning and going forward, will focus solely on the consolidated results of Enbridge Inc. I'm picking up here on slide 17, which summarizes Enbridge's consolidated financial performance for both the fourth quarter and the full year. By almost any measure, 2018 was a very strong year from a financial perspective. Adjusted EBITDA, adjusted earnings, and DCF all achieved record levels, driven by strong performance across all of our businesses. Consolidated adjusted EBITDA for the quarter came in at a little over CAD 3 billion, about 12% higher than the fourth quarter of 2017.
EBITDA for the full year came in just shy of CAD 13 billion, up approximately 25% when compared to last year. Bottom line adjusted earnings per share was up sharply, about 7% over the fourth quarter and just over 35% on a full-year basis. To be clear, a portion of the very strong full-year growth is attributable to the timing of the Spectra acquisition, which, as you recall, closed in the first quarter of last year. Our 2018 reported results reflect a full year's contribution from the legacy Spectra assets, whereas 2017 only included 10 months of results from the date of acquisition. There is a little noise between the two comparative periods.
A very significant component of this year's strong performance was the direct result of strong operating performance, ongoing asset optimization, and new contributions from over CAD 20 billion of new capital growth projects that we have brought into service over the last two years. Moving up to the top of the slide and looking a little more closely at the contributions from each of our main business segments. Liquids Pipelines adjusted EBITDA was up CAD 246 million for the fourth quarter and CAD 1.1 billion for the year. Performance drivers for both the quarter and full year are similar. The mainline system was full throughout 2018, with average deliveries ex-Gretna up 100,000 bpd compared to 2017, largely due to growth in oil sands production and capacity optimization initiatives that we undertook last year.
Mainline revenue was also positively impacted by an increase in the IJT toll and higher effective rates on the hedges we used to convert U.S. dollar toll revenue to Canadian dollars. The regional oil sands business benefited from a full year's contribution from large new trunk lines placed into service over the course of 2017, including the Wood Buffalo Extension, Athabasca Pipeline Twin, and the Norlite Pipeline. As well, the midcontinent pipelines and the Bakken system all continued to benefit from high utilization in the face of wide differentials and strong demand for transportation services. As noted on the slide, another factor giving a lift to fourth quarter performance versus Q4 of 2017 was the impact of a stronger U.S. dollar on the translation of earnings from our U.S. Liquids Pipelines operations.
While the average exchange rate for the full year didn't move very much between 2017 and 2018, when you isolate on the fourth quarter, the U.S. dollar actually strengthened about CAD 0.05. The stronger U.S. dollar resulted in stronger reported Liquids Pipelines segments EBITDA quarter-over-quarter. This uplift is substantially offset by the impact of our enterprise-wide FX hedging program, which we report under eliminations and other. Gas Transmission and Midstream adjusted EBITDA was down about CAD 68 million for the fourth quarter, but up over CAD 718 million for the year. The very strong full-year uplift was in part a function of the timing of the Spectra acquisition that I spoke to a moment ago. As a reminder, the majority of the assets we acquired through the deal reside in this segment. The decline in EBITDA quarter-over-quarter also requires a little explanation.
Firstly, the quarter-over-quarter picture was impacted by the absence of EBITDA from the U.S. G&P assets sold on August 1st and the provincially regulated portion of the Canadian G&P assets sold on October 1st. Secondly, while Gas Transmission benefited from incremental contributions from new pipelines placed into service in late 2017 and 2018, the two largest projects, the NEXUS Gas Transmission and Valley Crossing Pipeline, were placed into service during the last quarter of 2018. Q4 2018 does not reflect a full quarterly run rate from these assets. As well, the timing of operating and maintenance expense was more heavily weighted in the fourth quarter of 2018 than it was in 2017. Going the other way, reported EBITDA at GTM benefited from the impact of a stronger U.S. dollar on its U.S. operations.
As with Liquids Pipelines, this uplift was substantially offset by the impact of our enterprise-wide FX hedging program reported in Eliminations and Other. Moving down the slide to Gas Distribution. Adjusted EBITDA generated by our combined utilities increased by CAD 2 million for the fourth quarter and just under CAD 350 million for the full year. Similar to the transmission business, a portion of the very large step-up in full year earnings resulted from the inclusion of a full 12-month contribution from the legacy Union Gas assets as compared to 10 months in prior year. The performance of the combined franchises also benefited from higher distribution charges as a result of growing rate base and customer base, as well as the impact of new expansion projects placed in the service by Union Gas last year.
On average, 2018 was a little colder than normal, which positively impacted full year earnings approximately CAD 35 million or about CAD 0.02 per share. Looking at the quarter in isolation, Q4 2018 was relatively flat to 2017 due to higher recognition of earnings sharing at EGD in the quarter. Continuing on, Green Power was down about CAD 11 million for the fourth quarter, but up CAD 56 million for the full year relative to the comparable periods in 2017. Full year results were positively impacted by contributions from new projects coming into service, as well as better wind resources on average for the entire year, primarily in the first nine months. Q4 2018 was a little weaker than the last quarter of 2017. That's largely due to weaker wind resources and lower generation on systems undergoing repair, which more than offset new contributions from the Rampion Offshore wind project.
Energy Services continued to deliver strong financial results as it has done throughout the year. Adjusted EBITDA was up CAD 94 million for the fourth quarter and CAD 219 million for the full year when compared to the same periods last year. This was driven primarily by wider crude oil and natural gas location differentials, which created more opportunities this year to lock in profitable arbitrage margins. EBITDA reported in Eliminations and Other was up compared to last year, about CAD 94 million for the fourth quarter and CAD 59 million for the full year. The increase quarter-over-quarter is mostly due to the timing of the annual recovery of certain O&A costs from the business segments, which was more heavily weighted to the fourth quarter of 2018 relative to 2017.
This improvement was partially offset by the higher realized foreign exchange hedge losses on our enterprise FX hedging program that offset some of the business unit FX gains that I spoke to earlier. Reflecting both a stronger U.S. dollar and slightly less favorable hedge rates. Taken all together, a very strong and predictable performance from our businesses for the quarter and for the full year, as you would expect, given our low risk pipeline and utility business. Slide 18 shows how the growth in EBITDA I just went through translated to bottom-line distributable cash flow growth for both the quarter and for the full year. As Al has already highlighted, consolidated DCF for the full year came in at a record CAD 7.6 billion or CAD 4.42 per share, up on a per share basis just over 20%.
In line with expectations and close to the top end of the guidance range we established heading into the year. I'm not going to spend a lot of time on the full year comparison with 2017 for the line items below EBITDA, as most of the significant variances can be attributed to the timing of the Spectra acquisition last year. Focusing on Q4 and the first two columns of this schedule, you can see that the consolidated DCF was up about CAD 122 million over Q4 of last year. There were a few puts and takes explaining the quarterly variance. Maintenance capital was up a little from Q4 2017.
This was a function of a higher proportion of scheduled maintenance undertaken in the fourth quarter when compared to last year, offset by the absence of maintenance spending on the U.S. and Canadian gas gathering and processing assets that we sold in the second half of 2018. I want to point out that the unbudgeted sales of these assets is the primary reason we came in slightly lower than guidance on a full year of maintenance capital spend. Moving down the schedule, you can see that financing costs were higher as a result of the debt incurred and preferred shares issued to fund capital projects, slightly offset by the avoidance of debt due to the cash we received from divestitures.
You can also see that the adjustment for equity distributions in excess of equity earnings was lower in the fourth quarter of 2018 than in 2017, as increases in earnings from our joint ventures were not immediately matched with corresponding distribution increases. Current tax was also higher in Q4, largely as a result of stronger earnings from the operating segments and a provision for the full year impact of the BEAT tax introduced as part of U.S. tax reform. On a per share basis, DCF came in at CAD 1.03, which was down a couple of pennies over Q4 of last year. This is largely due to the timing of the buy-in of our sponsored vehicles. As a reminder, we issued close to 300 million shares during the fourth quarter of 2018 to take out the public's interest in each of our sponsored vehicles.
Given the timing of these transactions, the Q4 results don't reflect the full quarterly benefit of eliminating the sponsored vehicles' distributions to the public. Turning now to slide 19 and our outlook for 2019. This slide will look familiar as it highlights the guidance that we presented at Enbridge Day back in December, and nothing has changed here. The outlook for our core businesses continues to be very strong, and our guidance remains the same. We are projecting consolidated EBITDA of approximately CAD 13 billion for 2019, which is expected to drive out DCF per share in a range of CAD 4.30- CAD 4.60 per share. EBITDA growth in 2019 is expected to be driven by a number of factors, including continued strong performance from our core businesses, including an uptick from Line 3 before the end of the year.
The impact of a full year of operations from the CAD 7 billion of projects we brought into service in 2018, partially offset by the loss of EBITDA from the assets we sold last year, and the benefit of ongoing cost management and revenue optimization across our company, including anticipated synergies from the amalgamation of the two big utilities in Ontario. We've also shown our current outlook for 2020 on this slide. Consistent with Enbridge Day at CAD 4.85 - CAD 5.15 per share. The big driver of the 14% EBITDA growth over 2019 is the impact of a full year's contribution from the Line 3 replacement project, in addition to contributions from other projects coming into service and ongoing strong performance from the base business. No changes to our outlook for 2019 EBITDA or DCF at this very early stage of the year.
The 10% dividend increase we announced in December of last year remains very well supported. As we discussed at Enbridge Day, by 2020, we expect to be generating about CAD 3.5 billion of free cash flow after dividends and maintenance capital, which together with self-generated balance sheet capacity staying in line with our credit metric targets, should create about CAD 5 billion-CAD 6 billion of available cash to fund investment in new assets. As Al will come back to in a minute, we see plenty of opportunity to deploy this available capital into low risk growth projects. When combined with a steady underlying growth in our base business, this investment should drive our DCF per share growth to between 5%-7% post-2020 without the need for any follow-on equity offerings.
Beyond 2020, dividends will likely grow in line with cash flow, we'll make that determination on an ongoing basis as part of our capital allocation process. Turning now to slide 20, to close the loop on some outstanding action items on the debt side of things. At Enbridge Day, John noted that the buy-in of our sponsored vehicles would also provide an opportunity to simplify Enbridge's debt funding structure and strategy. With the buy-ins now behind us, we've been able to complete all of the key elements of our plan restructuring. These are highlighted on the slide and include the exchange of all outstanding public term debt of Enbridge Income Fund for senior unsecured notes of Enbridge Inc., with otherwise equivalent terms and maturity dates.
The implementation of cross guarantees between Enbridge Inc. and each of Enbridge Energy Partners and Spectra Energy Partners, effectively making all of this term debt pari passu with the debt of the parent company, Enbridge. The call for redemption in early February of CAD 400 million of Enbridge Energy Partners junior subordinated notes that we anticipate will be complete by the end of the month. These actions follow steps taken earlier in the year to redeem all of the outstanding external debt of Midcoast Energy Partners and the repurchase of redemption or redemption of virtually all of the remaining outstanding Spectra Capital term debt. We have now effectively discontinued external debt issuances by all of our wholly owned intermediate holding companies, including Enbridge Energy Partners, Spectra Energy Partners, Enbridge Income Fund, and Westcoast Energy.
As noted on the slide, we will continue to issue a certain amount of debt from operating subsidiaries and joint ventures where it makes sense to do so from a regulatory or a business perspective. Going forward, a much larger portion of our debt funding requirement will be met through issuances at the parent company. Taken together, these changes to our debt funding structure and financing strategy have reduced structural subordination, further enhanced the credit profile of the parent company and the consolidated Enbridge group, and should improve our relative cost of funding over the longer term. With that, I'll pass it back to Al.
Okay, thanks, Allen. Let me finish up with our strategic priorities on slide 21. They're really divided into two phases here. The ongoing ones, of course, are growing cash flow and dividends within our pipeline utility model, maintaining a very strong balance sheet and financial flexibility, and continuing to streamline the business as well as sound project execution. That's what is ongoing. You will see us increase emphasis in three areas, enhancing the returns from the core businesses and securing low capital intensity opportunities in each of them. Extending the footprint, especially targeted towards energy export infrastructure. We've talked about the positive fundamentals there that we see, and Guy and Bill have their priorities certainly set on this. And ensuring that we allocate capital to the most value-enhancing opportunities through the disciplined capital framework that we took you through at Enbridge Day.
This last point is a critical one. Let me summarize that on slide 22. Allen mentioned we've got CAD 5 billion-CAD 6 billion of available capital to invest annually by 2020. That's within the self-funding model, no common equity required there. We've got plenty of attractive accretive organic growth opportunities. In liquids, there's mainline optimizations, extensions and expansions of the downstream access, and the build-out of the U.S. Gulf Coast position. On gas, we're well-positioned to capture market-driven growth, particularly exports again, and modernization capital will be another source of growth. In utilities, we'll grow through annual customer adds, extensions to new communities, there's a number of those on the horizon, enfranchised gas pipeline expansion in the Dawn Corridor, which would provide a reliable CAD 1 billion a year of investment for the foreseeable future.
You can see plenty of opportunities here to invest in low-risk organic growth, combined with the base business to generate that 5%-7% growth per year. While our base plan is to grow organically, we'll always compare opportunities against alternatives to maximize shareholder value. Wrapping up on slide 23, let me come back to the bigger picture and the investor value proposition. The actions we took last year to streamline the business, strengthen the balance sheet, and refocus on a low-risk pipeline utility model set us up very well for the future, which we are excited about. We have three great franchises with a good balance between gas and oil and a strong U.S. footprint that will spawn a lot of growth.
That should allow us to generate that 5%-7% DCF per share growth well into the future, which we believe is a prudent growth rate for us. In summary, we're very pleased with how we're positioned today, and we're confident that the business model we've set up will generate strong shareholder value as we continue delivering on our plans. With that, we'll turn it back to the operator to open up the lines for the Q&A session.
Thank you. We will now begin the question and answer session. If you have a question, please press star one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star one on your touch-tone phone. Rob Hope is on the line, with Scotiabank is on the line with a question.
Hi, yes. Good morning, everyone.
Morning.
First question on Line 3. Appreciate the comments on the permitting process there. Just want to delve further into the flexibility of the construction schedule. When would you need crews in the field, and when would you need permits to ensure that the project is in service in 2019?
Okay. We'll let Guy talk to that.
To the first part, based on the plan that we're looking at right now to have the line in service by the end of the year, there's really no construction or seasonal issues that we would run into within that timeframe. I think that at the outside, we believe we will need to be in the field sometime in June to achieve that date.
All right. I appreciate that. Just moving over to conversations regarding contracts on Seaway and Flanagan. Also want to get a sense of whether or not you're in discussions with shippers regarding the potential to move volumes down cap line and whether or not there's a joint solution there.
It's Guy again. As you're aware, we're out talking to our customers about the contracting of the mainline, and certainly, some of the feedback that we're getting through that process is an interest in further market access to the Gulf Coast. We are working on a Flanagan South and Seaway expansion that will be part of that process. We've had conversations with shippers and with cap line owners on an ongoing basis. To the extent that our shippers do want to see what solution we can offer on the mainline that can line up with a cap line reversal, we'll be more than happy to engage with those shippers and with the cap line owners further.
Rob, maybe I'll just add a little bit onto what Guy said. If you look at the dynamics here, clearly, if you're a Western Canadian producer you want to get to the Gulf Coast. Right now, as Guy said, there's very strong interest given the mainline priority access that we're working on and, of course, the need for egress. People want to get out as soon as possible. We're moving forward with those two expansions on Flanagan and Seaway. Obviously, the producers would also like access to the other part of the Gulf, that's always been our desire as well to provide that additional optionality, particularly for heavy barrels in the Eastern Gulf. The base case right now is to move forward with those two expansions to the Western Gulf.
All right. I appreciate the comments. I'll hop back in the queue.
Our next question comes from Jeremy Tonet with JP Morgan. Your line is now open.
Good morning.
Hi.
I just wanted to start with the U.S. Gulf Coast here. It seems like between Colt and Gray Oak that you really have building on that platform nicely there. I was just wondering if you could speak a bit more about if you're seeing more opportunities, if this would be a bigger focal point going forward when you think about future growth.
Yeah. Jeremy, it's Guy. It is a huge focus of ours in Liquids Pipelines in terms of looking to leverage off of our existing asset base and extend our business in the Gulf Coast. You've mentioned a few of the things that we're working on now. We've got some others in the hopper that we're chasing. We're in the midst right now of staffing up our business development and commercial team quite substantially in Houston. It's something that is going to take on a lot more prominence in our growth efforts.
It's been a good story, Jeremy, actually, if you think about just a few years ago when there was no real access into the U.S. Gulf Coast. Obviously, we've been talking about our view of the fundamentals here around export markets, not just for oil but for gas. A big strategic priority of the company is to get more infrastructure positioned to export markets for both oil and gas. If you go back to Seaway, of course, Dakota Access, ECHO into the Gulf, and now with Gray Oak, we're really starting to build a meaningful position all the way through into the Gulf. It'll be a big area of focus for us, as Guy is saying.
That's helpful. Thanks. Turning to the gas pipe side, it seems like there's a lot of stuff on the drawing board as far as future opportunities there, and obviously, TETCO has a tremendous footprint. I was just wondering, Bill, in the field talking to people, where do you see near-term wins coming as far as converting stuff on the drawing board into a secure backlog project? Where are you having more success, I guess?
Thanks, Jeremy. Yeah, we're probably having the most robust conversations, again, in the Gulf, everywhere from South Texas, where, as you know, we recently completed Valley Crossing pretty successfully all the way around to the Louisiana Coast. I would say as the LNG developers are firming up their own plans and getting their offtake commitments, we're starting to see a lot more productive conversations, I'll say, in that region.
That's very helpful. Thanks. I'll get back in the queue.
Thanks, Jeremy.
Our next question comes from Linda Ezergailis with TD Securities. Your line is now open.
Thank you. I'm wondering with respect to your mainline discussions, what sort of pushback, if anything, are you getting for your proposed new toll contract structure and how might that unfold in the regulatory forum with the NEB?
Yeah, Linda. It's Guy. At this stage of the game, we're not seeing a great degree of pushback from any segment of customer, if you want to call it that. We're engaged with, I believe, in excess of 60 potential shippers on the mainline, understanding their situations and their needs. Really, our goal through that very massive engagement is to design a number of offerings that make it easy for people to access the system. We're dealing with producers, refiners, marketers. We're dealing with the very small guy talking about minimum commitments of as low as 4,000 bpd to the very largest who are up talking in hundreds of thousands of barrels a day. We're trying to make this very attractive to all and remove barriers from people to participate.
I think, Linda, the way that Guy and his team are working this, as he said, trying to make sure the offering is great for all of our shippers is really part of the regulatory outcome as well, we think. If we get enough support and a variety of support from different segments of shippers when it gets to the regulatory process, we think that will go very smoothly at that point.
That's helpful context. Maybe just as a follow-up for your operations, just wondering how you're seeing Energy Services continuing into Q1. Can we assume that things are still strong right now on that front, or are there other dynamics at play?
Well, I'll start off, Linda. No doubt Q4 was a pretty bang-up quarter with respect to Energy Services, and I think everybody understands the dynamics behind that. The basis in various markets for both oil and gas actually were very wide, and that allowed us to capitalize on some of our arbitrage strategies we have, particularly around location basis. I think it was a very strong quarter. I think we'll have a decent year. We've guided to around CAD 75 million, I believe, in 2019. That's probably a reasonable look at 2019, just given that some of the differentials have closed in, obviously, over the last month or two. I think it'll be strong. Not as robust a year as 2018, which was quite unusual, but still a very good outcome.
That's helpful. Thank you.
Okay.
Our next question comes from Dennis Coleman with Bank of America. Your line is now open.
Hi, this is Jasmine for Dennis. Just a quick question on simplification. Can you give some additional color, perhaps quantifying simplification's benefits to ENB's outlook post 2020?
Okay. Well, I think we've covered this in the past, but I guess at a very high level, Jasmine, the biggest benefit we think is simply the transparency it provides to our cash flows. I think it's fair to say that with the four sponsored vehicles we had out there, it was more difficult for people to appreciate that cash flow transparency and growth. I think that's probably the highest level benefit. Secondly, I would say that, as was mentioned by Allen, eliminating these intervening vehicles and keeping debt issued in one central place, generally at the holding company, will improve our simplicity with respect to structural subordination, and you saw the rating agency's reaction to that. There's other ancillary benefits, by the way, around the tax horizon, in particular, stepping up the tax basis on the investment. I think those are the big ones.
Don't forget too, you have these high payout vehicles, and obviously when you take them in, we've normalized the payout to what we think is a more conservative level. We retain more cash in the business, and that's also helpful from a credit perspective too.
Got it. Thank you. Going back to Line 3 replacement. At Investor Day, management shared that the current guidance assumes a November 1st in-service date. Has that assumption changed?
Well, as we mentioned in the remarks, or maybe it was, I guess, in the Q&A, we believe that Line 3 is still in service by the end of this year. I think for the purposes of our original guidance, we had assumed November 1. I don't think it's changed that much in that we still expect it to be in service by the end of the year.
All right. Got it. Thanks.
Okay.
Our next question comes from Robert Kwan with RBC Capital Markets. Your line is now open.
Great. Good morning. Just starting with the mainline contract offering. I'm just wondering, is there still, though, a formal dual track process between pursuing what you've laid out here and negotiations with representative shipper group for a CTS-like common carrier extension post mid-2021?
Robert, it's Guy. We're not negotiating a parallel path right now based on the strong interest in the path that we're on. There is a bit of a parallel path within the contracting discussion in that we're negotiating with a group of shippers who have stepped up to represent the spot shipper interest. As there will be capacity reserved for spot shippers, obviously there'll be a spot toll and issues around the spot toll. There is a parallel process that we have underway to tuck those guys in.
Got it. Maybe just finishing here on the Midwest pipes. Can you give a Line 5 update as it relates to the Bad River Band negotiations as well as just any interplay with the new governor in Michigan? On Line 3, if Minnesota does stall out on the DNR and the PCA permits, is there a remedy to try to get a faster approval, even if that's not the process you want to go at this point?
Yeah. Let me take Line 5 first. We've been actively continuing our engagement at Bad River, and there's really nothing more to report one way or another, other than we've operated there for a long time, and we continue to expect we'll operate there for a long time. In terms of Michigan, again, not a lot new to update. We're moving ahead with the plan to construct the tunnel. We've begun to receive some of the early permitting that we needed to do the geotech work this year. Obviously, we're aware that the governor has asked the attorney general to look at a few things. We're confident that the tunnel is the right thing, and we're going to continue to pursue it.
I think in terms of your question around Minnesota, there may be avenues to go down that path. I think our experience or the experience of others that have tried to do that, I think oftentimes it ends up adding time as opposed to saving time.
Yeah, maybe I'll just add on, Robert, on that point. For context here, again, the PUC process that we went through was extremely intensive, and that really sets the backdrop for this last permitting phase. I think you also have to go back to historical precedent for this. There's been a number We've been in Minnesota for 70 years and the number of times that we've built projects there. There is a fairly robust process for how we do permits in Minnesota. I think that is clearly the main approach that we're taking, and I don't think we're anticipating that we move away from that in this case.
That's great. Thank you.
Okay.
Our next question comes from Shneur Gershuni with UBS. Your line is now open.
Hi. Good morning, everyone. A lot of my questions have been asked and answered, but a couple of quick follow-ups. Really appreciate all the updates about the Line 3 in service and so forth. One of the partners, or I guess one of the owners of cap line, on their conference call a couple of weeks ago, talked about the fact that there would be a gap in service for when they can achieve heavy oil service on cap line reversal. The explanation they gave was that Enbridge was unable to contract additional capacity until late 2021. Can you walk us through that gap in timing when I think about when Line 3 comes online, versus when they think that they can actually receive heavy barrels? Is it a contract structure issue? Do you have 20% contracts to roll off? Just trying to understand the gap.
Okay. It's Al here. First of all, I'm uncomfortable speaking for them, but I guess maybe I'll make a couple of comments. I think through today we've been very clear about our expected timing for Line 3. I suspect, just looking at what they said, it may have something to do the confusion around when we expect CTS to be concluded, which as I said earlier, would be mid-2021. With respect to the disconnect with Line 3, you're going to have to get clarification from them on what they're talking about, because I think that we were pretty clear about our expected timing for Line 3.
Okay. Fair enough.
Yeah.
Another follow-up question on some of the growth projects that you have. Specifically, can you give us an update on the proposed VLCC export facility? I believe it's with Kinder Morgan and Oiltanking. How that's proceeding? Is there enough supply for another VLCC loader? I believe there's several competing projects out there. I was just wondering if you can walk us through that process and your thoughts on it.
It's Guy. I think the biggest update from when we spoke at Enbridge Day is that we did file our MARAD application a couple of weeks ago. That's in the works. I believe that process is going to take about a year. We got that in because we want to try and preserve the in-service date targets that we have out there of late 2021, early 2022. Our sense of the demand in that region is that in that timeframe that we're targeting, there is room for one. We do know it's a competitive environment, and I guess the biggest update is that we're continuing to compete. We've got a line of sight to some pretty significant customers, and we're doing our darnedest to get that project to the point where it's a secured investment.
Do you need the Seaway and Flanagan South expansions to come into service to make that whole thing work?
No. Obviously, our goal is to have as much upstream access as possible. To that specific question, the answer is no.
Perfect. Thank you very much, guys. Enjoy the weekend.
Okay. Thank you.
Our next question comes from Robert Catellier with CIBC Capital Markets. Your line is now open.
Hi. Good morning. I just have a couple follow-up questions on the CTS and the Gulf Coast. I'll start with the CTS. Have the mandatory production curtailments in Alberta impacted those discussions, and is there any market hesitation about recurring production curtailments?
It's Guy. We haven't seen any impact into those discussions or on the throughput on the mainline. We're coordinating very closely with the province in that regard because the province and the producing community recognizes that every barrel of oil that can move on a pipeline is a better barrel than either being curtailed or moved by rail. There's a tremendous amount of close coordination going on to make sure that somehow there's not an unintended consequence that we end up with spare capacity. We're not witnessing that at all. In terms of people's views of it longer term and what it may or may not mean through a contracting, there are some people that have raised that in the context of government interventions of one way, shape, or form. That's not a specific issue that we're having to necessarily address in the arrangements.
Clearly, people are looking at it.
I think, Rob, generally everybody has agreed, including the Alberta government, that the curtailments are not something that is a long-term plan. In fact, you saw some reduction in the curtailments already, and I think the whole purpose was to try and deal with some of the overhang on inventory. I think in the bigger picture, everyone would agree that these eventually will come off. I think it shouldn't really impact what we're thinking here on CTS.
Okay. Just with respect to the Gulf Coast. You're making some strides here in painting an improvement in the development outlook in terms of what you can do, Seaway, Flanagan, the Gulf Coast, all of it. How important is your success in building your presence in the Gulf Coast to a successful CTS outcome? Stated another way, if you had a full path to Tidewater, is that necessary, or do you think that leads to a better CTS outcome?
I think to put some context around it, we're looking at a mainline system that's post Line 3 is going to have over 3 million barrels a day of capacity. That's really the big piece of the recontracting effort that we've got going on. Looking at Flanagan South as an example, we think we can expand that by upwards of 250,000 barrels a day, which is not insignificant. I don't think you can draw a conclusion that says that 250,000 bpd on Flanagan South is going to be a major impact on how you end up tolling the balance of the mainline system.
I guess maybe, Rob, just again, I think Guy's got it covered well. In the very big picture, if you think about being a Western Canadian producer, generally speaking, I think it's been proven out over the last two, three years, the Gulf Coast market has always been and always will be very positive. A very good outlet, not just with respect to the export that we're talking about, but also just the pure refining capability in the Gulf, both on the Western and Eastern side. I think the bottom line is CTS is certainly, or the new CTS, whatever you want to call it, will be helpful in the ultimate goal of making sure more barrels can reach Tidewater.
Okay. Thank you.
Okay. Thanks, Rob.
Our next question comes from the line of Alex Kania with Wolfe Research. Your line is now open.
Great. Thanks. I just wanted to go back to slide seven, where you give the debt metrics. You're looking at your leverage recovery down to 4.3 x, I think was what the comment on the call was. Just philosophically, how do you think about that relative to the 4.5x-5 x level that you've thought about? Is it a good place to be? Do you feel like you'd want to trend back to that 4.5x-5 x level? Just curious what you're thinking as long term.
It's Al here. I think maybe the way to look at this is the 4.5x to the comfortably below 5x range is something that we think is a very strong long-term target for all of the reasons that you know about. It's the level where we can be very comfortable with that high investment-grade rating at triple B high. It gives us a very good degree of financial flexibility. In fact, if you look at the pipeline utility model, many utilities, as you would know would imply even higher debt to EBITDAs than we have here. That's the model that we have. I would say as far as the amount that's below the 4.5x-5x range there that pops up in 2020, we look at that as some very nice extra buffer, will give us some additional financial flexibility.
Bottom line is four and a half to below five is the range we feel very comfortable with. Obviously, when you can have some additional flex, if opportunities arise that you can capitalize on, then that's good too.
Great. Thanks. Just one last question just on Texas Eastern on the rate case. I'm just curious what the response has been from shippers. Is there maybe a potential for inter-rate implementation timing on that? How much do you have baked in with respect to revenue enhancement in terms of the long-term plan? Thanks.
Yeah. As far as what we've got baked in, we probably won't comment on that. I think the phase that we're in with the Texas Eastern rate case is that we're getting a number of interrogatories back from interested parties. If you're a party to the rate case, you're allowed to ask a bunch of questions, and we're busy formulating answers to those. Where we're going to go is, we'll wait for what's called the top sheets to come out in April, and then we've got our first settlement conference in May. That's the general progression that we'll be going through.
Great. Thank you very much.
Okay.
This concludes the question and answer session. I will now turn the call over to Jonathan Gould for final remarks.
Great. Thank you, Liz. Covered a lot of good ground here today. As always, our IR team will be available right away to take any additional follow-ups that you may have. Thank you, everyone, for your time and interest in Enbridge, and have a great day.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.