Enbridge Inc. (ENB) Q4 2018 Earnings Report, Transcript and Summary

Welcome to the Enbridge Incorporated 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 in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for the investment community. [Operator Instructions] 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, and welcome to the Enbridge Inc's 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 and I encourage those listening on the phone to follow along on line with the supporting slides. A replay and podcast of the call will be available later today and a transcript will be posted to the website shortly thereafter. In terms of Q&A, we will prioritize call from the investment community only. If you're a member of the media, please direct your inquiries to our communications team who'll 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. So please try to limit your questions to one and a follow-up, if necessary. And as always, our Investor Relations team is available for your more detailed follow-ups or modeling questions afterwards. Onto Slide 2, where I'll remind you that we will be referring to forward-looking information on today's call. By its nature, this information contains forecasts, 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. So with that, I will now turn the call over to Al Monaco.

Thanks, Jonathan, good morning, everyone. We finished the year strong with another very good quarter. And with that, 2018 is now in the books, and with the 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 Whelan is here today, but he's lost his voice over the last couple of days. So Allen Capps will review the results and financial outlook later on. I'll wrap up with our priorities heading into '19 and beyond. Slide 4 is the checklist that we established for ourselves at the beginning of last year after completing the integration of Spectra, a major priority, delivered strong results for the first full-year after the deal. Another was to move to pure pipeline-utility business model because that's where we're best at. That meant selling non-core assets and accelerating deleveraging. 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 course. At the same time, the goal is to replenish secured growth beyond 2020. So that's what we set out to do. So let's look at the scorecard now starting with the financial results on Slide 5. Our business, no doubt, fired on all cylinders last year, and we delivered record numbers. EBITDA, as you saw, came in at almost $13 billion and distributable cash flow at $7.6 billion. That translates to $4.42 in DCF per share, which is at the high end of the '18 guidance range of $4.15 to $4.45. And that's a 20% increase year-over-year. Q4 came in at $1.3 per share, is very good result. Same strong story on adjusted earnings at $0.65 a share for the quarter and $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 1.65x, so very strong as well, and we increased the dividend another 10% to $2.95 per share for 2019. Allen will get into more detail on the results. Turning to Slide 6 and the asset sales, we initially targeted $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 $8 billion for the year. The valuations we got confirmed these were excellent capital allocation moves for us for non-core assets. But the multiples also highlighted how valuable our core pipe and utility assets are today. Bigger picture of these transactions got us to a pure play utility pipeline model we were targeting in just one year. And their size also significantly accelerated deleveraging and gave us additional financial flexibility. And on that note, as you see on Slide 7, debt to EBITDA came down to 4.7x at year-end, well below the original 5x target we set for '18, and down markedly from around 6x in 2016. We also reached that our long-term leverage target range to 4.5x to comfortably well 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 at 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. Equal importance, faster deleveraging allowed us to shut off the drip sooner. That was last step in moving to a fully self-funded capital model. On to Slide 8, 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 has 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 expanding our nontaxable horizon. Bottom line, this infrastructure is a big plus and allows us to focus energy on the core businesses as we should. On the next slide, at our Investor Day, we announced $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 propositions very well. We think the key one is the Gray Oak pipeline out of the Permian, which fits nicely with our strategy to build the 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 to 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. Onto Slide 10, we brought over $7 billion of projects in the service last year. And our remaining secured inventory now stands at $16 billion. That actually includes a recently secured regulated electricity transmission investment in Northern Ontario. In fact, earlier this week, we received the lead to construction, 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 service type project with our share around $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. So in the last two months, we've added another $300 million in growth capital to the 1.8 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 expansion 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 lowest 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 $460,000 barrels per day of capacity. And Guy and his team are working on a number of additional near-term and longer-term enhancements, and from our customers' standpoint, the sooner the better. The most immediate is a 50,000 to 100,000 barrel per day additional opportunity to move Alberta barrels my midyear. And that’s obviously much needed in a curtail production environment in Alberta. Because of the reliability and optionality that the mainline provides, there is very strong shipper interest in our priority access contract offering. And we've talked about the key features of that, which are seeing here on this slide. Discussions with the industry are moving along very well, and we expect to launch an open season sometime in Q2. If all goes well, we should be in a position to fire with ENB 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-'21. Also to complement that, we’re seeking additional commitments on Flanagan South and Seaway, which were underpinned further expansion on those systems. Onto Slide 12 and a Line 3 update. So this project is obviously a lot of interest. So let's first provide some context because the project is unique and that it's not a greenfield build. Rather, it’s a replacement of 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 land owners, communities and indigenous and tribal nations. These groups along the entire right away support replacement and want us to get it done. And that was the conclusion reached in Minnesota, after our 43-months regulatory review, one of the best and most thorough that we've seen. The projects also helps keep energy cost 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 are ready to go. Line 3 will generate millions in annual property tax revenue to support services the counties and municipalities are looking forward to and are planning to have. So clearly this pipeline is critical and it has massive support. So with PUC approval, we’ve reached the final permitting and construction phase of the project with regulators in all jurisdictions having now approved it its full steam ahead on the remaining project execution phases. Now in Canada, actually, we have all 1,100 kilometers of pipe welded up in the ground and backfill. By the way, again, a great partnership here with First Nations and main key groups were proud of what we've done with them in creating that partnership, and it's going to serve we think as a great model in the future. There is still lot of work to do in Canada on pump stations and terminal tie-ins, but we expect to have all of that complete and the pipe-ready to line fill by the beginning of June. In Wisconsin, the pipe is already replaced and was put into service last year. In North Dakota, we tied in the border crossing already and there is above 50 miles yet to construct likely this summer. Getting back to Minnesota, as I mentioned, we are now in the permitting phase. So I will take a bit more time on that one on the next Slide. First of all, the nearly 4-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 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 was 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. And actually we'd 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, so this is really no different. So here’s the status on the permitting. Recall that we submitted all the federal, state and local permits and 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 are 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 vendors to affect our in-service timing this year. So with timing approvals, we still expect to be able to bring the line into service before the end of 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 onto Slide 14, and the update on Gas Transmission. 2018 was a strong year for system utilization and 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 re-contract over 98% 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 US 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 liability peaking supply from oil generation and foreign LNG imports. And 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 case. That allows us to rebase and recover the capital we've invested overtime, and as we execute on modernization that needs to be done. We filed our Texas Eastern rate case with the FERC last November, and we're possessing that with our customers. With ongoing modernization capital, we will likely be filing full rate cases on Algonquin and East Tennessee as well. Over 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 send out for couple of those days at 7 Bcf. 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 Bcf of capacity in the region. As of January 1, Cynthia and her team have bought our two utilities into one single operation. And there is 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 5-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 buying of our four sponsored vehicles we have now brought virtually all of our assets under the umbrella of a single publicly traded entity. So I'm going to run through the numbers this morning, and going forward we will focus solely on the consolidated results of Enbridge Inc. I’m taking 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 little over $3 billion, about 12% higher than the fourth quarter of 2017. EBITDA for the full year came in just shy of $13 billion, up approximately 25%, when compared to last year. And 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 that full-year's contribution from the legacy Spectra assets whereas 2017 only included 10 months of results from the date of acquisition. So there is a little noise between the two comparative periods. However, a very significant component of this year strong performance was the direct result of strong operating performance, ongoing asset optimization and new contributions from over $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 Pipeline's adjusted EBITDA was up $246 million for the fourth quarter and $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 barrels per day 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 rate on the hedges we use to convert U.S. dollar toll revenue to Canadian dollars. The regional oil sands business benefited from four years' contribution from large new truck lines placed in the 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 continue 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 the 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 $0.05. The stronger U.S. dollar resulted in stronger reported Liquids Pipelines segment's EBITDA quarter-over-quarter. However, 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 $68 million for the fourth quarter, but up over $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 two minute -- a moment ago. As a reminder, the majority of the assets we acquired through the deal reside in the 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. E&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 in the service in late 2017 and 2018, the two large projects, NEXUS and Valley Crossing pipelines replaced in the service during the last quarter of 2018. So 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 and 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. Although as with liquid 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 $2 million for the fourth quarter and just under $350 million for the full year. Similar to the Transmission business, a portion of the very large step-up and full year earnings resulted from the inclusion of a full 12-month contribution from the legacy Union Gas assets as compared to 10 months than prior year. However, 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 $35 million or about $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 ETD in the quarter. Continuing on Green Power was down about $11 million for the fourth quarter, but up $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, and that's largely due to a 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 $94 million for the fourth quarter and $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. Finally EBITDA reported in Eliminations & Others was up compared to last year, about $94 million for the fourth quarter and $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 expect too earlier, reflecting both the stronger U.S. dollar and slightly less favorable hedge rates. So taken all together of 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 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 $7.6 billion or $4.43 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 the schedule, you can see that the consolidated DCF was up about $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 the 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 to the cash we received from divestitures. You can also see that the adjustment for equity distributions and excess of equity earnings was lower in the fourth quarter of 2018, then 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 The U.S. Tax Reform. On a per-share basis DCF came in at $1.03, which was down a couple of pennies over Q4 of last year. This is largely due to the timing of the buying of our sponsored vehicles. As a reminder, we issued close to 300 million shares during the fourth quarter of 2018 to take up the public's interest in each of our sponsored vehicles. But given the timing of these transactions, our 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 $13 billion for 2019, which is expected to drive out DCF per share in a range of $4.30 to $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 the full year of operations from the $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 the slide, again consistent with Enbridge Day at $4.85 to $5.15 per share. The big driver of the 14% EBITDA growth over 2019 is the impact of the full year's contribution from the Line 3 Replacement project, in addition to contributions from other projects coming in the service and ongoing strong performance from the base business. So no changes to our outlook for 2019 EBITDA or DCF at this very early stage of the year, and 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 $3.5 billion of free cash flow after dividends and maintenance capital, which together was self generated balance sheet capacity staying in line with our credit metric targets should we create about $5 billion to $6 billion of available cash to fund investment in new assets. As I will come back to you in a minute, we see plenty of opportunity to deploy this available capital into low risk growth projects. When combined with the steady underlying growth in our base business, this investment should drive our DCF per share growth to between 5% to 7% post-2020 without the need for any follow-on equity offerings. Beyond 2020, dividends will likely grow in line with cash flow, but we will make that determination on an ongoing basis as part of our capital allocation process. Turning now to Slide 20, and to close the loop on some outstanding action items on the debt side of things. At the Enbridge Day, John noted that the buying of our sponsored vehicles would also provide an opportunity to simplify Enbridge's debt funding structure and strategy. With the buyings 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. And the call for redemption in early February of $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 should redeem all of the outstanding external debt of Midcoast Energy Partners, and the repurchase of 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 business perspective by going forward on 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 enhance the credit profile of the parent company and the consolidated Enbridge Group and should improve all relative cost of funding over the longer term. And with that, I will pass it back to Al.

Okay. Thanks, Allen. I’d like to finish up with our strategic priorities on Slide 21. And they are 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 some project execution. So 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 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. So let me summarize that on Slide 22. Allen mentioned we got $5 billion to $6 billion of available capital to invest annually by 2020. Again, that's within the self-funding model. So no common equity required there. We’ve got plenty of attractive accretive organic growth opportunities. In Liquids, there is 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 would 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, in-franchise gas pipeline expansion in the Dawn corridor, which would provide a reliable $1 billion a year of investment for the foreseeable future. So you can see plenty of opportunities here to invest in low risk organic growth combined with the base business should generate that 5% to 7% growth per year. And while our base plan is to grow organically, we will always compare opportunities against alternatives to maximize shareholder value. So wrapping up on Slide 23, let me come back to the bigger picture, in 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% to 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 are confident that the business model we set up will generate strong shareholder value as we continue delivering on our plans. And with that, we'll turn it back to the operator to open up the lines for the Q&A session.

Thank you. [Operator Instructions] Rob Hope is on the line. Rob with Scotiabank, he's online with a question.

First question on Line 3, appreciate the comments on the permitting process there. And 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.

Yes, so 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 is 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.

And then just moving over to, I guess, 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 Capline and whether or not there is a joint solution there?

Yes, so, it's Guy again. As you're aware, without 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 Capline owners on an ongoing basis. And to the extent that our shippers do want to see what solution we can offer on the mainline that can lineup with a Capline reversal. We will be more than happy to engage with those shippers and with the Capline owners further.

Yes, Rob, maybe I'll just add a little bit on to what Guy said. If you look at the dynamics, you are clearly -- if you’re a Western Canadian producer, you want to get to the Gulf Coast. And right now, as Guy said, there is 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. So we’re moving forward with those two expansions in Flanagan and Seaway, obviously, the producers would also like access to the other part of the gulf. And that’s always been our desire as well to provide that additional optionality, particularly for heavy barrels in the Eastern Gulf. But the base case right now is to move forward with those two expansions to the Western Gulf.

Our next question comes from Jeremy Tonet with JP Morgan. Your line is now open.

I wanted to start with the U.S. Gulf Coast here. And it seems like between Colt and Gray Oak that you really have kind of building on that platform nicely there. But I was just wondering if you could speak a bit more about -- if you're seeing more opportunities is this would be kind of a bigger focal point going forward when you think about future growth?

Yes, Jeremy, it's Guy. There 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 were chasing. We are in the mix right now of staffing up our business development and commercial team quite substantially in Houston. So 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 the few years ago, when there was no real access into the U.S. Gulf Coast, and obviously, we've been talking about on our view of the fundamentals here around export markets, not just for oil but for gas. So a big straight strategic priority of the company is to get more infrastructure position to export markets for both oil and gas. And so, 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. So it would be a big area of focus for us as Guy saying.

And turning to the gas pipes side, it seems like there is 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 kind of near-term wins coming as far as converting stuff on the drawing board into kind of the secured backlog project? Where are you having kind of more success, I guess?

Yes, we’re probably having the most robust conversations again in the Gulf, everywhere from South Texas where, as you know, we've recently completed Valley Crossing pretty successfully all the way around to the Louisiana Coast. So I would say as the L&G developers are forming up their own plans and getting their off-take commitments. We're starting to see a lot more productive conversations, I'll say, in that region.

Our next question comes from Linda Ezergailis with TD Securities. Your line is now open.

I’m wondering with respect to your mainline discussions, what sort of pushback, if anything, are you getting for your proposed neutral contract structure. And how might that kind of unfold in the regulatory forum with the NEB?

Yes, Linda, it's Guy. At this stage of the game, we’re not seeing a great degree of pushback from kind of 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. And 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. So we’re dealing with producers, refiners, marketers, we're dealing with the very, very small guy talking about minimum commitments of as low as 4,000 barrels a day to the very largest to -- talking in hundreds of thousands of barrels a day. So 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. And 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, very smoothly at that point.

That's helpful context. And maybe just as a follow-up for your operations, I'm 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. So, I think it was a very strong quarter. That would be unusual, if you look at the context of all of our history on Energy Services. I think we'll have a decent year. We've guided to around $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. So, I think it will be strong. Not as robust a year as 2018, which was quite unusual, but still a very good outcome.

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. So, 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 agencies' reaction to that. There's other ancillary benefits, by the way, around the tax horizon, in particular, stepping up the tax basis on the investments. So, 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 more conservative levels. So, we retain more cash in the business and that's also helpful from a credit perspective too.

And 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. So, I think, for the purposes of our original guidance, we had assumed November 1. So, I don't think it has changed that much in that we still expect it to be in service by the end of the year.

Our next question comes from Robert Kwan with RBC Capital Markets. Your line is now open.

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. We are -- there is a bit of a parallel path within the contracting discussion in that we are negotiating with a group of shippers who have stepped up to kind of represent the spot shipper interest, as there will be capacity reserve for spot shippers. Obviously, there will be a spot toll and issues around the spot toll. So, there is a parallel process that we have under way to tuck those guys in.

And maybe just finishing here on the Midwest pipes, can you give a Line 5 update as it relates to the Bad River negotiations, as well as just any interplay with the new governor in Michigan? And 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 a process you want to go at this point?

So, let me take Line 5 first. So, 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 geo-tech 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 but 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. So …

Yes, maybe I'll just add on, Robert, on that point. I mean, 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. And there's been a number. I mean, we've been in Minnesota for 70 years and a number of times that we've built projects there. So, there is a fairly robust process for how we do permits in Minnesota. So, 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.

Our next question comes from Shneur Gershuni with UBS. Your line is now open.

A lot of my questions have been asked and answered but a couple of quick follow-ups. I really appreciate all the updates about the Line 3 in-service and so forth. 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 from when they could achieve heavy oil service on cap line reversal. And the explanation they gave was that Enbridge was unable to contract additional capacity until late 2021. Can you walk us through the 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 to wait for some contracts to roll off? I'm just trying to understand the gap.

Well, 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 with the confusion around when we expect CTS to be concluded, which, as I said earlier, would be mid-2021. But 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.

And 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.

Yes, so, 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. So, 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 '21, early 2022. Our sense of the demand in that region is that, in that timeframe that we're targeting, there is room for one and 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 are darndest 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 but, to that specific question, the answer is no.

Our next question comes from Robert Catellier with CIBC Capital Markets. Your line is now open.

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 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. So, 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. So, 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. So, that's not a specific issue that we're having to necessarily address in the arrangements but, 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. So, I think, in the bigger picture, everyone would agree that these, eventually, will come off. So, I think it shouldn't really impact what we're thinking here on CTS.

And just with respect to the Gulf Coast, you're making some strides here and painting an improvement in the development outlook, in terms of what you can do, Seaway, Flanagan, the Gulf Coast, all of it. So, 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, post-Line 3, is going to have over 3 million barrels a day of capacity. And 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, but I don't think that you can draw a conclusion that says that 250,000 barrels a day 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. But 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 or three years, the Gulf Coast market has always been and always will be very, very positive and 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 sides. So, 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.

Our next question comes from the line of Alex Kania with Wolfe Research. Your line is now open.

I just wanted to go back to Slide 7, where you give the debt metrics. When you're looking at your leverage hovering down to 4.3 times, I think what the comment on the call was, just, philosophically, how do you think about that relative to the 4.5 times to 5 times level that you've kind of thought about? Is it a good place to be? Do you feel like you want to trend back to that 4.5 times to 5 times level? I'm just kind of curious what you're thinking of long-term?

It's Al here. So, I think maybe the way to look at this is the 4.5 to comfortably below 5 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 BBB-high. It gives us a very good degree of financial flexibility. In fact, if you look at the pipeline-utility model, many of the utilities, as you would know, would imply an even higher debt to EBITDA than we have here. And that's the model that we have. I would say, as far as the amount that's below the 4.5 to 5 range there that pops up in 2020, we look at that as some very nice extra buffer and will give us some additional financial flexibility. So, bottom line is 4.5 to below 5 is the range we feel very comfortable with but, obviously, when you can have some additional flex, if opportunities arise that you can capitalize on, then that's good too.

And then just one last question, just on Texas Eastern and the rate case. I'm just curious what the response has been from shippers. Is there maybe a potential for interim rate implementation and timing on that? And how much do you have baked in, with respect to revenue enhancement, in terms of the long-term plan? Thanks.

Yes. So, 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. So, if you're a party to a rate case, you're allowed to ask a bunch of questions and we're busy formulating answers to those. Really, 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. So, that's the general progression that we'll be going through.

This concludes the question-and-answer session. I will now turn the call over to Jonathan Gould for final remarks.

Great. Thank you, Liz. We 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. So, 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.