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Welcome to the Enbridge Inc., Enbridge Income Fund Holdings, Enbridge Energy Partners and Spectra Energy Partners Fourth Quarter Fiscal Results Conference Call. My name is Amanda, and I will be your operator for today's call. [Operator Instructions] Please note, this conference is being recorded.I would now like to turn the call over to Jonathan Gould, Director, Investor Relations. Jonathan, you may begin.
Thank you, Amanda. Good morning, and welcome to our Q4 call this morning. With me here I have Al Monaco, President and CEO of Enbridge; John Whelen, EVP and Chief Financial Officer; Guy Jarvis, Executive Vice President, Liquids Pipelines; and Bill Yardley, Executive Vice President, Gas Transmission and Midstream.Our joint call will, again, include discussions for all of the Enbridge entities, including Enbridge Inc., Enbridge Income Fund, Spectra Energy Partners and Enbridge Energy Partners. This will allow us to provide a consistent enterprise-wide strategic and financial perspective, while at the same time, weaving in some specific commentary on strategy and performance of each of the Sponsored Vehicles.Note that we've developed supplemental information for each vehicle to ensure that we can continue to provide full and transparent disclosure for each. Some of this information is appended to the presentation here today, and has been posted to the various company websites. As per usual, this call is webcast, and I encourage those listening on the phone line to follow along online 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, given the broad agenda and limited time we have available, we will prioritize calls from the investment community only. If you are a member of the media, please direct your inquiries to our communications team, who'll be happy to respond immediately. We're, again, going to target keeping the call to roughly an hour and may not be able to get to everyone. [Operator Instructions] But as always, we will ensure that our Investor Relations team will be available for your more detailed follow-up questions afterwards.Before we begin, let me point out that we will refer to forward-looking information on today's call. And by its nature, this information contains forecast, assumptions and expectations about future outcomes. So we remind you that it's subject to the risks and uncertainties affecting every business, including ours. This slide includes a summary of the significant factors and risks that could affect Enbridge and its affiliates and are discussed more fully in our public disclosure filings available on both SEDAR and EDGAR.So with that, let me now turn the call over to Al Monaco.
Thanks, Jonathan, and good morning, everyone. I'm going to start off with a brief recap of '17, and then the key priorities through 2020, and then cover off our quarterly business update. John's going to review the financial results for Enbridge and the Sponsored Vehicles, and talk about the implications of U.S. tax reform across the Enbridge Group. So we may take a few minutes longer in our remarks today to make sure we get our views out on that one.So on to Slide 4, we had a very busy 2017. The Spectra deal transformed Enbridge from what was mostly a Canadian liquids pipeline company into a North American oil and gas -- oil and natural gas infrastructure business. We quickly integrated the assets and hit our year 1's synergy target.While we were doing that, we quietly put $12 billion of projects into service, our largest program ever, on time and on budget. Operationally, we had a very good year. We optimized throughput, minimized downtime and maintained our leading safety performance. Results wise, we came in at $3.68 per share in distributable cash flow, that was within the guidance range. We were very pleased with Q4, which gives us momentum into 2018, where we expect to see a nice uptick in growth.Sponsored Vehicle numbers came in well, as you saw. Their outlook is stable, and we made headway on streamlining. Another important item was our post-Spectra strategic review, which we landed on our 3-year plan and priorities. So let me recap those on the next slide.Number one, we're moving to a pure pipeline utility model. Liquids Pipelines and terminals, natural gas transmission and storage and gas utilities, all of which generate highly predictable cash flows and come with embedded growth. That means we'll sell or monetize noncore assets, which include U.S. and Canadian gathering and processing and our onshore renewables, $3 billion of which is targeted for this year. Although no longer core to us, these are strong businesses that would be very attractive to strategic and financial buyers. We've kicked off the process, and we've seen a lot of interest right out of the gate.Number two is to accelerate deleveraging to our goal of 5x debt to EBITDA by the end of this year. This will happen through the combination of growing EBITDA, noncore asset monetization and a prudent funding plan, a good plan for funding, and we're focused now on completing it.Third, our $22 billion secured capital program will support expected 10% DCF and dividend per share CAGR through 2020.Our fourth priority is to continue to streamline. The Spectra-related synergy capture is on track to achieve the $540 million target, and we now think there's even more opportunity. We've got a 3-year continuous improvement program that targets top quartile cost performance.And finally, we're always looking at ways to extend growth, but we will be disciplined on how we allocate capital. That means investing and growing our 3 core businesses, because that's where our competitive advantage lies and where we can earn the best return.Let me now move to our business update. As we kick off the year, the business fundamentals are strong in our view. Western Canadian crude supply is growing from the large-scale oil sands projects, and we have rising North American and global energy demand, all of which is supportive of infrastructure growth.There's 2 economic factors that are top of mind right now, U.S. tax reform and interest rates. On tax reform, we've gone through our initial assessment. John will cover that, including the impact on Sponsored Vehicles. The bottom line, though, is that based on our review, we don't see a material impact to distributable cash flow to Enbridge over the 3-year financial outlook we presented at Enbridge Day.Beyond 2020, lower tax rates will surely be positive for the business. With long bond yields creating some jitters in the market, our conservative financial policies insulate us from rising rates. We do that through locking in rates on hedges, a prudent maturity profile and floating rate debt limits. Our commercial agreements also mitigate exposure. For example, our liquids mainline CTS toll has an annual inflation escalator, tolls on Lakehead have an indexing and cost passthrough mechanism that accounts for rising rates, and our new utility rate application includes a revenue escalator for inflation.As you know, we manage economic factors very closely through our risk management policies and cash flow at a risk framework. And you can see on the slide that our CFaR is less than 3%.Switching gears now to the outlook on the Liquids Pipelines business. We're very pleased with the recent performance and outlook for the Mainline, and the chart that we have configured here tells that story. If you go back over the last while, we've expanded the system and more recently completed several optimization projects to maximize throughput. Because of upstream supply disruptions, though, this is the wildfire, as you recall, back in '16 and the Syncrude stoppage last year, we really haven't been able to take full advantage of the increased capacity. But in December, the combination of growing WCSB supply and strong refinery demand drove record deliveries of 2.733 million barrels per day ex Gretna, which is close to maximum capacity. You can see that with a narrowing throughput to capacity gap on the slide.January and February volumes look pretty strong as well, and we expect that the system will essentially be full for the rest of the year. In fact, we expect that to be the case through 2020, including our Line 3, given growing supply and lack of other pipeline capacity before that. That means a pretty strong Mainline outlook through 2020.But what about beyond that for plan competing pipelines, which we do assume go ahead for our planning purposes. There are several important factors that underpin the continued strength of the Mainline in that environment. So let me just spend a minute on that on the next slide.Most of you know that the system that we operate out of Western Canada offers great market reach and highly competitive tolls. And it has the operating flex and crude slate optimization that nobody else can really provide. There's confidence in WCSB supply growth now, but equally important is the downstream part of the equation that provides strong market pull dynamics, and here is why. The Mainline is directly connected to 1.9 million barrels per day of upper PADD II refineries, which are heavily reliant on Canadian crude. PADD II represents some of the highest priced net backs for crude, and when combined with our competitive toll, offers producers net backs that can be $5 higher than the alternatives. And we've put this on the chart that you see and the numbers that are reflected there are really a post-2020 assessment of our tolls.For example, in December, PADD II took roughly 1.7 million barrels per day of crude, which drives home the competitiveness of these PADD II refiners taking barrels from our system. Now even though if Canadian barrels wanted to get to the Gulf coast, given the wide basis, PADD II refiners were very competitive in buying WCSB barrels. Another aspect of market demand fundamentals for our Mainline are the take-or-pay contracts, up to 1 million barrels per day to Montreal, Patoka, Cushing and the U.S. Gulf. You'll recall that's through our market access pipelines, namely, Line 9, Southern Access Extension, Flanagan South and Seaway.So it's for those reasons that beyond 2020, we're confident that the Mainline will remain highly utilized. So in summary, here's the way we look at the competitive dynamics post 2020. In a one new pipeline scenario given the production forecast, we expect to be largely full and will likely be in an expansion mode on the Mainline. In a 2 new pipeline scenario, the competitiveness of our tolls, flexibility of the system and the strength of market pull will ensure very strong throughput.Now turning to execution on Slide 9. Now this slide recaps the full list of projects that we've put into service last year totaling $12 billion. This is history, so I won't dwell on them, but they're included here to emphasize that these are low-risk solid-return projects, generally low-teen returns on equity that are going to drive cash flow growth in the coming years. In fact, it's the key driver behind our strong 2018 growth outlook.Slide 10 shows the next phase of organic growth projects we have in execution. The '18 to '20 capital program is $22 billion, on which we're making good headway. As you can see, the slate of projects is very well diversified by size, region and commodity. We're forecasting $6 billion of projects coming into service next year, not quite the same load as we had last year, but we continue to be very sharply focused on executing these.Let me provide a brief update on 3 significant projects on the next slide. First, NEXUS provides much needed export capacity for gas out of Utica and Marcellus. It's a good example of how our large footprint now can facilitate growth as this pipeline ties into our Vector system to ultimately deliver into our LDCs in Ontario.Construction is well underway in Michigan, and we'll be starting up in Ohio shortly. And Bill and his team here are very focused on doing a top-notch job, especially from an environmental and community engagement perspective.Another good news story is the Valley Crossing pipeline in South Texas. Construction is almost 80% complete there, it made great progress. This will be a critical link to serve growing gas-fired power demand in Mexico. And as you can see on the map here, the footprint is very well positioned to capture further growth opportunities in the Gulf Coast and Permian.Last on this slide, on the Rampion Offshore Wind Project. This is, as a reminder, a very large facility of 400 megawatts of capacity. All 116 turbines are now in and connection to the grid is underway. We expect full operation in the second quarter of '18. So good progress on these projects. Now let me move to Line 3.As a reminder, Line 3 is a critical infrastructure project that will further enhance the reliability of our system. This will be a truly world-class pipeline, utilizing the latest in materials, construction and technology. We have strong support for the project, landowners, communities, First Nations and refiners, who all want to see this project built as soon as possible, and they're actively supporting our efforts.Our 2017 program went well. In Canada, we're about 400 kilometers done and pump station work is underway. The construction team is getting excellent support from the communities, and we're pleased -- very pleased to have provided $75 million of direct business opportunity to First Nations communities along right-of-way.Construction in Wisconsin is also done and will be tied in next quarter. In Minnesota, the project has undergone, I would say, the most extensive and inclusive review of any pipeline project. In January, the PUC reconfirmed the regulatory time line, which was a good outcome. A recommendation on the route and need permits to the PUC on April 23 will come from the ALJ. And the PUC has indicated, it expects to make a decision at the meeting in June. So we continue to expect the project to be in service in the second half of '19.Before I turn it to John, just a quick update on Sponsored Vehicles from me. As most of you know, in November, we made an offer to eliminate the GP incentive distribution rights at SEP. The objective there was to reduce SEP's cost of capital, so it could capitalize on future opportunities. And we see SEP as a very important part in growing our overall natural gas business. So with this change, obviously, SEP will be better able to position for organic growth, acquisitions or potentially dropdowns from Enbridge. And I think all of this aligns us very well, being unitholders and the shareholders.We finalized this transaction in January, and we believe it's a good win-win proposition. All the vehicles now, we believe, are well positioned with sound balance sheets, good distribution coverages and attractive value propositions.So with that, I'm going to hand it over to John now for his review of the numbers.
Well, thanks, Al, and good morning, everyone. I'll pick up here on Slide 14, with a quick snapshot of the consolidated results. You may recall at our investor days back in December, we introduced adjusted EBITDA as our primary operating performance metric replacing adjusted EBIT. We also noted that going forward, we'd refer to ACFFO as distributable cash flow or DCF. As you will have seen, our year-end news release and this morning's presentation reflect these new conventions.To be clear, nothing has changed in the definition or calculation of these metrics. This is simply an alignment of presentation format and naming conventions across Enbridge's publicly listed vehicles. As you can see on the slide, consolidated adjusted EBITDA was up $1.2 billion for the quarter, a little over $3.4 billion for the year when compared with 2016.Clearly, a big part of the increase in EBITDA was driven by the operating assets acquired in the Spectra transaction in the first quarter of 2017. But the strong year-over-year performance also reflected higher contributions from a number of our legacy operating assets and the partial year impact of the $12 billion of new organic growth projects that we successfully brought into service over the course of the year.The growth in DCF is primarily driven by these same factors. As Al mentioned, for the full year, we came in at $3.68 per share, well within our guidance range. Although a little below the midpoint given a few factors that I'll touch on as I go through the results on a segmented basis. DCF for the fourth quarter came in at $1.05 per share, up over 10% when compared to the fourth quarter of 2016, reflecting a few factors: Performance, generally is expected from legacy Enbridge and legacy operating assets; the impact of new growth projects coming into service; and the realization of cost savings and merger synergies, which continued to grow over the course of 2017.Turning to Slide 15, and drilling down now into the key drivers of EBITDA growth for both the quarter and the full year. And starting with Liquids Pipelines, where adjusted EBITDA was up $157 million for the full year and $127 million for the fourth quarter, driven in large part by higher volumes in the Mainline system, which achieved record deliveries in December. With the benefit of a very strong year-end, volumes on the Mainline are up 5% on average for the full year, despite the unexpected disruption we saw at upstream production facilities in the second quarter, driven by continued growth in oil Sands productions and enabled by the system capacity optimization initiatives that we undertook last year.New regional oil sands projects coming into service and contributions from the Express-Platte system acquired through the Spectra transaction also contributed to the year-over-year growth in liquids.Gas transmission and Midstream is what we used to refer to as gas pipelines and processing prior to the Spectra merger. It includes all of Spectra's legacy gas transmission and gathering and processing assets and investments. And here, adjusted EBITDA was up very significantly, largely due to the contributions of the assets that we acquired through the merger. Year-over-year growth reflects both contributions from Spectra's operating assets, plus the impact of expansions brought online during 2016 and 2017, primarily on the Texas Eastern and Algonquin transmission systems.Overall, GTM segment results were bolstered by a strong performance at DCP Midstream, improved fractionation margins at Aux Sable and solid performance from the Alliance Pipeline, offset to a degree by weaker volumes and processing margins on our legacy Midcoast G&P assets. Our sale process for the Midcoast assets is well advanced. And as you will have seen, we have classified these assets as held-for-sale on our financial statements and marked them down to an accounting estimate of fair value. And this impairment flowed through our GAAP earnings in the fourth quarter.Moving down the slide, the primary driver for the increase in the contribution from Gas Distribution is the inclusion of 10 months of EBITDA from Union Gas, which we acquired through the merger. We no longer normalize for the impacts of weather at our utilities, and both Enbridge Gas Distribution and Union Gas benefited from significantly colder-than-normal weather in the fourth quarter, which partly made up for some somewhat warmer-than-normal weather in the early part of the year.Despite the colder Q4, the impact of weather on full year adjusted EBITDA from the 2 utility operations was slightly negative, about $18 million or $0.01 per share of DCF. Adjusted EBITDA generated by our green power and transmission assets was up over 2016 for both the fourth quarter and full year results, as a result of stronger wind resources across the entire North American portfolio and from contributions from the Chapman Ranch wind farm in Texas that was placed into service in the fourth quarter of 2017.Energy Services continued to be negatively affected by low commodity prices, which affected location and the quality differentials, which in turn, resulted in fewer opportunities than last year to achieve profitable margins on assets where we have capacity obligations. Some of these obligations have now expired, which should help improve performance within this segment going forward.Finally, turning to Eliminations and Others. Recall that this is the segment where we book settlements associated with our corporate FX hedging program. These hedge gains and losses serve to partially offset corresponding FX losses and gains that are captured in the EBITDA reported by our business segments that have U.S. investments. The year-over-year improvement of about $79 million in E&O is primarily due to lower hedge settlement losses, which resulted from both a stronger Canadian dollar and higher effective hedge rates.So when taken all together, a good quarter and a pretty solid first year as a combined company with contributions from our new Spectra assets generally right in line with expectations.Slide 16 shows how the growth in EBITDA I just went through for each business, translated the bottom line DCF for both the quarter and the full year when compared to 2016. I'm not going to spend a lot of time on this slide today as most of the significant various items for the line items below EBITDA for both the quarter and the full year can be attributed to the combination with Spectra. As I pointed out earlier, the fourth quarter and full year DCF results are in line with what we anticipated at the time we provided guidance after closing the deal back in February.On to Slide 17, and a new item this quarter and one that's getting a lot of attention and that's U.S. tax reform. The Tax Cuts and Jobs Act is a complicated piece of legislation, and there are a number of components that still require further clarification, either through more detailed regulations or other forms of interpretive guidance, which we expect will be forthcoming from the U.S. Treasury in the coming weeks and months.As required, we've made reasonable estimates of the impacts based on our current read of the legislation and booked provisional amounts where possible, which we have disclosed in our financial statements and MD&A. From an accounting and reporting perspective, this has resulted in the recognition of a one-time noncash benefit of approximately $2 billion on a consolidated basis in the fourth quarter, reflecting the net impact of remeasuring our U.S. deferred tax liability at a lower go-forward tax rate. This amount flows through our fourth quarter GAAP earnings, but is normalized for the purposes of determining adjusted EBITDA and DCF for the quarter and the full year. At this time, we don't expect U.S. tax reform to have a material economic effect either through impacts to cost of service revenue or on the cash taxes we pay. We do own assets that incorporate a tax allowance in the determination of their cost of service revenue either embedded in negotiated contracts or through rate-regulated toll mechanisms.However, as I'll get to in a moment, the net impacts of the tax rate change on these assets with negotiated cost of service formulas is essentially neutral to Enbridge at the consolidated level. It's also important to point out that a very significant and growing proportion of our consolidated revenue is generated from negotiated tolls and rates that are embedded in long-term contracts and divorced from a strict cost of service formula. For more closely regulated assets, which do include a tax allowance in their recourse rates, we expect that any potential to these rates would be determined in conjunction with a rate-case proceeding that would take into account a variety of other incurred and perspective costs and adjustments.In recent years, we have substantially built up our U.S. gas transmission rate base and have yet to file for a return on any of that. This along with the other cost of service factors suggests a net rate increase. We're looking hard at a filing rate case -- filing a rate case on Texas Eastern and other pipes to reflect all of these changes. As such, we don't anticipate an impact on SEP's current DCF outlook as a result of tax reform and potential rate cases.While we still need further clarification with respect to how certain elements of the tax reform legislation will work in practice, over the long term, we see a reduction in U.S. tax rates as being positive for the company. And at this time, we don't expect that the impact of the various components taken together should have a material impact on cash taxes or our bottom line DCF outlook through our 2020 planning horizon.With respect to our Sponsored Vehicles, the good news is that the legislation maintained the competitive tax advantages for MLPs relative to corporate structures through at least 2025. When it comes to the impacts on cost of service revenue to our Sponsored Vehicles on a stand-alone basis, the immediate and potential commercial impacts of tax reform are a little different at each. And I'll touch on these when I review the financial performance and outlook for each of these vehicles.Turning now to Slide 18. This will look familiar as it highlights the segmented guidance that we presented at Enbridge Days back in December. Nothing has really changed here. Our 2018 outlook for the core business continues to be strong. And as I just noted, we don't expect any material impact on revenue to arrive from tax reform. We continue to expect very solid year-over-year growth in EBITDA, just over 20%, driven by a number of factors, including the impact of a full 12 months of contributions from the legacy Spectra assets we acquired at the end of February last year, continued strong performance from our core businesses, particularly the liquids pipeline systems, where we'd expect Mainline system throughput to remain very strong, the input of a full year of operations from the $12 billion of projects Al noted that we brought into service in 2017, and of course, partial-year contributions from new projects scheduled to come into service in 2018. Although the larger ones are weighted towards the back half of the year, which will help support growth into 2019. So no changes to our outlook for EBITDA or DCF at this early stage, and our 10% dividend increase announced in December of last year remains very well supported.Moving on now to the performance of our Sponsored Vehicles, which all delivered solid results in 2017, either in line with or a little better than expectations. I'm starting on Slide 19 with highlights for Spectra Energy Partners or SEP. At SEP, ongoing EBITDA was up sharply over 2016 on both a quarter-over-quarter and year-over-year basis, while ongoing DCF for the full year came in at about $1.53 billion, a little bit above the upper end of our guidance range. The story here is in many respects similar to previous quarters this year. Very steady performance from base assets and a big contribution from $2 billion of accretive organic growth projects that we placed into service over the course of the year.SEP continued to increase its distribution by $0.0125 per share each quarter, which translated to an increase of approximately 7.3% relative to last year and is expected to continue to grow its dividend at the same rate every quarter through the end of 2018.In connection with U.S. tax reform, SEP has booked an $860 million noncash charge to 2017 GAAP earnings. Effectively, the accounting rules require us to establish this regulatory liability for amounts collected through rates in respect of deferred taxes that could become refundable to shippers over time as a result of the reduction in the U.S. federal tax rate.To be clear, this accounting charge has no immediate impact on SEP's rate base or its current tolls. As I said before, we believe that any potential rate refund would most likely be considered in connection with a future rate case, which would take into account a variety of other incurred and prospective costs in the determination of new rates and, within any event, be amortized over a very long period approximating the remaining life of the assets.While the timing of any such rate case remains uncertain, we don't anticipate, as I said before, a material impact on SEP's DCF outlook as a result of tax reform.Turning now to Enbridge Energy Partners on Slide 20, adjusted EBITDA was down relative to the fourth quarter and full year 2016 results, but this was expected, given the sale of the Ozark assets last year and of course the sale of the Midcoast G&P business to Enbridge as part of the restructuring we completed earlier this year.EEP finished 2017 strongly, delivering adjusted EBITDA of USD 1.76 billion, just under the upper end of our pro forma post-restructuring guidance with DCF a little above the upper end of the guidance range. Performance of the Lakehead Mainline was steady and in line with expectations, reflecting its regulated and largely cost of service tolling framework. 2017 results also benefited from contribution from EEP's interest in the Bakken Pipeline system that was placed into service on June 1, 2017.Tax reform did not result in any accounting specific impacts to EEP's 2017 financial statements given the manner in which the EEP toll is determined and integrated with the Canadian Mainline toll. However, there will be a reduction of revenue from certain assets, whose tolls are based on a facility surcharge mechanism, which includes a tax allowance in the determination of cost of service. We estimate the net impact to EEP DCF at approximately $55 million annually. And as you'll note on this slide, we reduced our 2018 adjusted EBITDA and DCF guidance to reflect this revised revenue outlook.Finally, turning to Slide 21 and highlights for ENF and the Fund Group. Fund Group DCF was up $74 million from Q4 of last year and $139 million from 2016, in line with guidance. Growth was driven primarily by higher throughput and higher tolls in the Canadian liquids Mainline, strong demand for seasonal firm capacity on the Alliance natural gas pipeline and better results from the fund's green power facilities, which benefited, again, from stronger wind resources in the second and fourth quarters of 2017.Fund Group DCF is expected to [ stay neutral ] in 2018, with revenue on the Mainline driven by higher average throughput, a higher effective FX hedge rate and a full year's contribution from the regional oil sands pipelines we placed into service last year. And the longer-term outlook continues to support 10% annual dividend growth at ENF through 2020, as we announced at Enbridge Days.The Fund Group does hold some U.S. assets in its portfolio, which are impacted modestly by U.S. tax reform. In the fourth quarter of 2017, we recognized a noncash charge of $52 million related to the remeasurement of the deferred tax asset that occurred as a result of the reduction in U.S. tax rates. This amount has been normalized in the determination of Fund Group DCF.Looking forward, on balance, the Fund Group will actually benefit modestly from tax reform. As I noted earlier, EEP's FSM tolls will be reduced as a result of the reduction in U.S. tax rates. To the extent, the EEP tolls go down, ENF will see a corresponding uptick in its Canadian Mainline toll revenue under the existing international joint-tolling framework. The increase isn't large enough to change our guidance for the Fund Group or ENF at this stage, but it certainly provides a nice tailwind earlier in the year. So with respect to tax reform, ENF is up a little bit, EEP's down a little, and we don't expect a near-term impact on SEP. As noted earlier, the impact to Enbridge's consolidated revenue are essentially neutral.Before I turn it back over to Al, I wanted to briefly touch on funding on Slide 22. The plan we rolled out at Enbridge Days is depicted graphically on the right-hand side of this slide and designed to accelerate deleveraging and strengthen the balance sheet, while cost-effectively financing our $22 billion secured capital growth program. The plan continues to be highly executable and is designed to achieve our longer-term credit metrics by the end of 2018, and provide further strengthening of those metrics over the balance of our 3-year planning horizon to increase go-forward financing flexibility.As we discussed at Enbridge Days, we're targeting to bring down debt to EBITDA as we define that ratio to 5x by the end of 2018, and comfortably below that level as we execute on our current capital program and seek opportunities for growth. At the same time, we'll look to bring FFO to debt up to 15% by the end of 2018, and maintain that ratio comfortably above that longer-term target going forward.S&P, Fitch and DBRS have all reaffirmed their BBB high-level ratings based on their comfort with this plan. You will have seen that Moody's downgraded Enbridge to BAA 3 stable back just before Christmas. We were disappointed with this action, but our plan remains the same, and we're confident that it will deliver the target metrics that they have publicly outlined for a BAA 2 rating by the end of 2018 based on our outlook for the business. Executing the funding plan is very much a strategic priority in 2018. Our asset monetization plans continue to progress and are on track. We've made a good start on funding with a $2.6 billion of common and preferred equity we raised across the group in December, and we'll be proactive in tapping hybrid and debt markets to meet the balance of our funding requirements for the year. The plan is flexible and provides for a number of alternate sources of equity-equivalent financing that we can draw upon to meet the balance of our equity funding requirements, which could support turning off the drip sometime within the current plan horizon.And with that, I'll turn it back to Al to wrap up.
Okay, John. As I said, that we took a bit longer today to get that information out, but I'll wrap up quickly here. Really, the main point that we want to make to close this off on the remarks is, I think, we've rolled out a very strong plan through 2020 that really charts a path for us going forward of strong DCF and dividend growth rate of 10% through that period, while still focusing on our core businesses and bolstering our financial flexibility even further.So overall, we believe the plan is solid, the outlook is strong and execution is going to be a key focus for us in '18 on the key priorities that we outlined.So with that, we'll turn it over to the Q&A session.
[Operator Instructions] Our first question is from the line of Jeremy Tonet of JPMorgan.
I want to touch on a Reuters' article with regard to potentially accelerating some of the asset sales, and just wondering, if you could address that? And is that a possibility it's something that you might want to do?
Okay. Well, glad -- I'm actually glad you raised that, Jeremy. I saw that article as well yesterday. I guess, maybe -- the first thing I'd say is I'd use that information with caution since it's not from us. So I would treat it as suspect. But let me just back up here, the plan we rolled out at Enbridge Day is in place, which was -- we designated noncore asset sales of $10 billion. It's actually probably higher than that level. We indicated very clearly that the target for 2018 was $3 billion. That's in our plan, and that's incorporated into the guidance. We've got a very solid funding plan, as John just talked about, many options and levers to pull if need be. And there's certainly nothing that indicates to us that additional asset sales would be required. But obviously, as we always would, if there are ideas that come forward or offers that are put on the table that we can't turn down, then we'll probably have a look at those. So it's good to have optionality here, but really only if it enhances the plan as we've laid out at Enbridge Day.
That's helpful. I guess, it's always important to take it from the horse's mouth here. Just wanted to also touch on the Mainline as well. And it seems like you're currently tracking above the midpoint of your guide for next year. And was just wondering if there's an element of conservatism built in there? Or is there issues down time that you're expecting or interruptions? Anything with Line 5, some of the regulatory issues there that you could update us on? Or anything else we might not be thinking of because it seems like you're kind of trending above that?
Yes, I'll start it out. Jeremy, it's a good observation. We are a little bit above that budget level at the moment, at least, we were in December and January looked good, as I said. I think at this point, we're probably close enough to the budget that there's no real significant change or view that we have at this time. It's pretty close to the budget. So I would say, we can take it at that. I don't know, Guy, if you want to add anything to it.
Yes. I mean, I think the only thing I would add about December is to get up into that type of record throughput levels. Obviously, production has to be to working, refineries need to be working, and you have to be a good spot inventory-wise across your system. So those 3 things all came together and delivered that record volume. But as Al said, we can't -- we shouldn't expect that we'll be able to do that every month.
That makes sense. And just Line 5, is there anything new on the regulatory side that you guys are expecting there or...
No. Nothing new. We have -- we're executing on the 7 pieces that we committed to the state under our agreement. We've met any of the deadlines that were in it to date, and we continue to plan to meet all the other deadlines that are in it through the balance of the year.
Our next question comes from the line of Robert Kwan of RBC Capital Markets.
Just wondering, in the MD&A under the U.S. Sponsored Vehicle strategy, there is some new language there mentioning things like potential consolidation, sales, securities and changes to capital structure. I recognize that it's pretty broad and you've covered pretty much the entire waterfront, but you're pretty careful with wordings. So I'm just wondering what we should take from that?
Well, I guess, maybe at the high level then I guess, John, you can comment as well on the MD&A. But at this point, we feel pretty comfortable with where we are on the Sponsored Vehicles. I think at Enbridge Day, we laid this out. Basically, I think over the last year, we've done a couple of things that were helpful in terms of streamlining and simplifying. If you go through them, MEP was taken out, the SEP IDRs, on EEP, obviously that involved a larger restructuring that I think was helpful. At this point, we need a little bit more seasoning to EEP to hopefully see that through. And so really we haven't changed our position at the moment on the Sponsored Vehicle strategy.
I don't think I've got anything to add to that. We're always careful on our MD&A to ensure that the full gamut of our strategy is laid out. So it's just consistent with our normal practice.
Understood. If I can finish with a question on the Mainline. With the Mainline fall and the heavy spreads that we've seen or just the spreads we've seen for Western Canada, you've got some of the incremental expansions that you held out there. I'm just wondering how you're thinking about them with respect to, are they tied in many ways through a renegotiation of CTS and you getting things that you want such as minimum volume commitments? Have you seen an acceleration of discussion with customers about getting at some of that stuff maybe sooner than later? And as well, are there any discussions? Or do you think that the customers understand that the Mainline may be the best way to socialize the insurance of excess capacity for the baseline?
Okay. Well, again, I'll start it out. I think those are very good questions, Robert. At a high level, the customers in the Western Canada really see the Mainline as having excellent attributes, and we went through those in the discussion. And they certainly are encouraging us to talk about and review the expansions with them as they move through a number of other alternatives, I guess, in terms of the pipeline space. So for sure, they're encouraging us to move those along. In this environment, obviously, if you're a producer or a refinery, you'd like to see all the potential opportunities developed and that's certainly the case for the Mainline, just given the attributes around the low-cost nature to the key markets, the scale, the optimization, the segregation that we can provide. So I would say that's number one. Number two, with respect to CTS, we would expect that we get moving along on that discussion. I think you know that those discussions would normally start 2 years before finalization of CTS. So that would be 2019, and we're getting some encouraging feedback around wanting to move forward on that. So there's nothing definitive yet, but certainly positive on both fronts. Guy?
Just maybe add 2 things. First off, just to reaffirm, we do have work plans in place for all of those expansion projects. So we do continue to work all of them. There is not a lot that has to take place around them in 2018, but we're keeping our eye on all of them. I think just to add a little bit around the tolling piece, the competitive -- the beauty of these things is their competitiveness. So when we've looked at most of them within the context of the current CTS deal, we don't believe we would need a surcharge mechanism or anything like that for most of these. They would just roll right into the CTS. So they're going to be very competitive and should fit very well, whether it's the tail end of this CTS or whether it's into our next tolling agreement.
Our next question is from the line of Andrew Kuske of Crédit Suisse.
Maybe just keeping with the Mainline topic, and if you could just highlight your effective connectivity into Patoka? And then options that you may be looking at as far as Capline goes and the Capline reversal?
Okay. Andrew, it's Guy. So we can get into Patoka or that vicinity in 3 ways. So we can get in there from -- we make deliveries into the Mustang system that delivers in there, Mainline deliveries into the Mustang system that can get there. Of course, Southern Access Extension can get us into that market. The Platts system gets us down into that market, it's not an absolute direct connection, but we've got a number of ways, Mainline and otherwise, to get barrels into Patoka. We've always said we're very interested in that Capline reversal. And like I think the rest of the industry are waiting to hear from the Capline owners what their next steps might be.
I think part of that Capline opportunity is it's very much linked to Line 3 and the timing of that project going into service. And that would kind of make it all fit together, the pieces of the puzzle in terms of getting more crude into the eastern part of the U.S. Gulf Coast, which is, again, as Guy said, we've seen a lot of encouraging signs around people wanting to commit on Capline. So I think it could fit together quite nicely when Line 3 comes in.
That's helpful. And then a follow-up and a little bit farther out in time. How do you think about just the potential for Southern Lights to be reversed and then repurposed?
Well, certainly, that's something that we've had in our expansion plans. And I think we haven't really done a deep dive into that just yet, but it seems to us that the emerging fundamentals for natural gas in Western Canada directionally would be supportive of having more native condensate in the basin. And certainly, if that emerges, it will have us looking seriously at the flow direction of Southern Lights.
Yes. It's a good illustration, I think, Andrew, of having a big footprint and scale in the system. And of course today, we've seen a lot of repurposing of infrastructure. So the Southern Lights is running fine at the moment, but a very good upside for us. And importantly, for the producers, again, getting back to the previous question around how we could make additional expansion capacity available getting into the key market in PADD II.
Our next question is from the line of Darren Horowitz of Raymond James.
Quick question for Bill on NEXUS. Considering the plan to have that remaining 40% plus or minus of that line contracted by 2020, based on what you're seeing with the tariff dynamics into Dawn, it's getting increasingly competitive. What negotiated rate do you now have built into the guidance for remaining excess capacity? Is it fair to assume something like what was negotiated with Union in the mid-to-high 70s plus fuel or cost inflation? And if so, does that still suggest that the return on the project should achieve a high single-digit rate?
Yes, Darren. So basically, we haven't disclosed for obvious reasons what the negotiated rates are with any of the shippers. So what I would say is that the marketing efforts that will continue over the next 2 years to get to our target for that 40% would be in the ballpark of what -- the expectation is still that we're in the ballpark for what the original contracts are both with the producers and with the LDCs. And bear in mind, there's a ton of load in the middle of Ohio that we've had some fairly productive discussions with that doesn't rely on Dawn pricing necessarily. So I'd say, overall, the assumption of whatever we've sold -- the prices, the rates that we've sold today would hold forth for the other 40%.
Okay. And then just a quick follow-up on Valley. When can you guys view the optimal timing for the dropdown, especially in light of bonus depreciation and the tax benefit? And then pro forma, the incentive distribution rate collapsed. How does that change possibly Enbridge's appetite for incremental SEP equity or the composition of how you would finance that drop?
Well, perhaps, these are questions that John can chime in on. But certainly, for the Valley Crossing drop, I'm not sure there's an optimal time other than after it's in service. So I would say, at some point thereafter. On the IDR question, I think, from my vantage point, it certainly does make SEP a fairly competitive vehicle in the marketplace and an attractive source of funding. But, John, I don't know if you had anything else to add on that.
No, I don't. I mean, we've always said that Sponsored Vehicles are one way that we can push forward, raise funds across the group, whether we're doing things organically or whether we're doing things by way of acquisition from third parties or potentially acquisitions from Enbridge Inc. So keeping that currency strong is all part of the strategy.
I don't want to extend the answer too long, but I do think it's important just to draw some larger context around this, and that is, part of the thinking around the IDRs, as I mentioned in my remarks, was allowing SEP and capitalizing on SEP, frankly, to grow the natural gas business. So I think your question on Valley Crossing is good. That's the most obvious one. But remember, there is perhaps even a broader suite here to think about. Vector, as you heard earlier, with respect to NEXUS and moving gas and other's gas into the market in Ontario is a very strong line. And we've also got some other assets, particularly highly contracted offshore assets that could be attractive for SEP as well. So there's a belly of dropdowns. Not to mention, obviously, SEP has some good organic growth opportunities in front of it as well.
And our next question comes from the line of Ben Pham of BMO.
I wanted to go back to the asset monetizations. And I'm wondering how do you guys think about prioritization and what asset package to tee up in terms of timing. And maybe using Midcoast as an example, like, why Midcoast over onshore renewals first?
Okay. Well, again, I think at this point, the plan includes the sale of $3 billion. Now we haven't been specific, purposefully, as to what's included in the $3 billion. We've itemized the 2 general categories being G&P and renewables. Frankly, we're seeing a very strong reaction to what we've got out there so far, mostly G&P, probably top of the order just given timing, but also very strong indications for renewables. And I think, Ben, that the market for those assets is very strong today. So I would say it has to do with having some good options and flexibility depending on what we see out there. And so I think that's how to look at this. The Midcoast assets themselves, remember, have, after the restructuring, been, I guess, cleaned up per se in that an asset sale there is a lot simpler compared to where the assets were held before. Those could be sold in on block or by parcel, whatever it takes to generate the best value there and make sure we hit the target for this year of $3 billion, like we said. So I think it's a bit of a flexibility in option depending on what we see.
Okay. And then secondly, your other funding strategy of the hybrid market. We've seen governments move, but Moody's yields haven't moved at all. I mean, is there any big change in the hybrid market at all from a funding perspective?
It's John, Ben. No, I think actually we're seeing a fairly good receptivity. And we've been unusually transparent in terms of what our plan looks like. So we've heard queries out there, you're right, the underlying treasuries have gone up a bit, and I would say we are hedged to a degree on that. Meanwhile, we've actually probably seen spreads tick in a little bit. So both in terms of price relative to what we were anticipating, but also market access, I think we feel pretty comfortable right now.
Our next question is from the line of Linda Ezergailis of TD Securities.
Maybe I'll ask some operational questions with respect to your tracking ahead of plan on synergy, with respect to the Spectra integration. And I'm wondering what the nature of the potential further synergies that you're seeing is in terms of timing and scale?
Okay. Well, I'm not going to be too specific about the scale other than to say, as I said in my early remarks, that the big picture objective is to get to top quartile on cost. But with respect to synergies, this sort of goes in order of, I guess, certainty, if you want to look at it that way, Linda. I think the first year here, it's highly transparent because it's generally elimination of duplicate functions. So that's kind of like the labor component of it. Next in line would be other costs that can be eliminated through review of processes and simplification and so forth. I'd say, we're well into that. And then there's a third element of it, which relates to supply chain, and that's probably a larger opportunity even just given the mass of both operating and capital that we put to work every year. So going through that with a fine-tooth comb and generating that, those tend to take a little bit longer because they involve a process change and they involve a lot of discussion with suppliers and so forth. So that's kind of the batting order of the 3 categories.
Okay. And just as a follow-up, your services business -- Energy Services was challenged again in Q4. Can you comment on how Q1 is looking? Are there may be some sort of transportation and storage obligations that are creating a drag for 2018? And are there perhaps other market intelligence benefits for your corporate development group that justifies running the segment on a continued loss?
It's John, Linda. Yes, I mean, to the latter question first, I think that's absolutely right. We have -- we always have a benefit there in terms of the -- having ear to the market, if you will, in terms of what's going on and understanding logistics as they apply not just in our own systems, but around the entire grid. With respect to the outlook, I think I did mention in my remarks that some of the capacity obligations that have been a bit of a burden over time will be relieved up over the course of this year. So I think that will be helpful for that segment.
Yes. Just more broadly in terms of the general strategy and support for the business, if you look back over time, the business has been very strong in generating value from the low-risk arbitrage opportunities we have in place. So where we can provide blending, where we can capture basis differentials and where we can provide storage, these are all, I would say, very much core to the overall infrastructure business. And I think we will, hopefully, get some help from the items that John mentioned around some of the commitments rolling off. So we should see a better 2018. And based on where we see some of the dips right now, we're hopeful for that business.
And Q1 is looking good then? Or it's better?
It's certainly been better in Q1 compared to where we saw basis last year. So we're hoping it's a better quarter than the fourth.
Our next question is from the line of Robert Catellier of CIBC Capital Markets.
I did have a couple of questions. So first with U.S. tax reform. Can you comment on the interest deductibility caps of U.S. tax reform and the exemption for utilities? And how those might impact the company and the availability of any mitigating strategies you might have to offset those impacts?
Robert, it's John. Yes, I mean, it is a complex piece of legislation, and there are a lot of interwoven parts. And for a company like ours that has a very big gas business, regulated utility business, but also has a very big liquids business and other businesses in the portfolio, it's a bit of a balancing act. There are lots of things, quite frankly, that we think we can do to manage over that over time. And as I said in my remarks, we don't think the net impact is actually going to be significantly material, especially for a company that's carrying fairly significant loss positions down in the U.S. at this particular point in time. But we're watching for the emerging detail that will come out of treasury as we go to do this. But as we look at the scenarios and the interpretations, I think we're pretty comfortable in terms of where we'll come out going forward in terms of our taxability arising in our cash tax profile.
So the neutral outlook includes the impact of interest deductibility caps?
Yes. We've -- I'm putting that in there and with the caveat that we're obviously continuing to wait for some clarification, because the implementation rules aren't very clear. It's a pretty big piece of legislation, and there's still some regulation to come. But I think we're pretty comfortable at the end of the day.
Sure. Understood. I appreciate the complexity issue. Now the second question has to do with the recently revamped major project process in Canada. I'm wondering how it impacts how you -- basically, your willingness to put development dollars at risk and how you might -- how it might change your capital allocation plans.
That's an excellent question. Maybe I can just summarize it this way. I think everybody would agree that there has been regulatory uncertainty for a while, and that is causing investor concern and obviously concerns from us as well in terms of where we put capital to work. I would comment that, generally we're supportive of the government's goal to increase the confidence in the process. And we're thinking that the direction is right in terms of aspects of the legislation. So for example, there hasn't been any change as far as we can see in how day-to-day operations are overseen, I guess, by the regulator in Canada. That's important because there's a lot going on other than major projects in terms of regulation. There has been no change with respect to the current projects we have under way until new legislation gets in. So that's good. There are some shorter time lines that have been proposed for new projects, in some cases, not all. And I think it's positive that the goal was to address indigenous issues, which has been, obviously, part of the issue with respect to major projects. Some of the concerns, though, obviously, whenever you have a major change to legislation for regulation is it's always difficult. And there is, I would say, a degree of overall complexity that we're looking at going forward in the future. So I would say, there's still some level of unpredictability until we see the legislation, and there'll be continued uncertainty, I think, for a little while. But the good news is that we're still working very hard with the government to make sure that we're providing all of the input as they form their legislation. But I guess, to go to your broader question, we're going to be very cognizant of where we put capital. And we heard about U.S. tax reform, which is positive for the business. And so obviously, that will be a factor in where we look as well as driven by where the opportunities are. So a long-winded response, but that's our view on regulatory reform today coming out of what we saw.
Yes, that's helpful, especially juxtaposing that versus the improved environment from tax reform.
Our next question comes from the line of Rob Hope of Scotiabank.
Just a question on the Sponsored Vehicles. We've seen you exchanged the GP interest for LPs at SEP. But when you look at the rest of the suite of Sponsored Vehicles and MLPs, are there other simplification measures that you're contemplating? Or longer term, could we see a reduction in the number?
Well, let me start by saying this, Robert. We certainly are not blind to the fact that people prefer simplicity in this market, which we agree with. We've inherited, obviously, a couple of vehicles here with respect to the Spectra deal. I think we've taken some pretty good actions so far given that it's been the first year we've been working on it. We're going to -- I guess, maybe the bottom line is, we'll continue to evaluate to see if there's any of those opportunities to simplify further. So I think that's probably -- that's our view at the moment. And until we see something different, we will continue to look at it.
All right. And then just one follow-up on the Mainline. The 2.7 that you did in December, I know you've done a very good job eking out kind of incremental capacity over the last couple of years. Is there more work to be done in '18 there? Or is the -- are we reaching the upper limit of the effective capacity there?
It's Guy. I think to this point in time, we've kind of exhausted the list of opportunities that we've seen. Again, the key feature of what we've tried to do is create opportunities to make better utilization of the light capacity in our system. Historically, we've seen a bit of a pattern of a drop-off of light volumes into the spring and through the summer. And our target is to try and make better utilization of that capacity if that happens. So we've got a series of different plans that can meet upwards of 200,000 barrels a day of that type of capacity. And it's unlikely you would see them all work at the same time. But certainly, they are there. And at this stage of the game, we really don't have any others that are under way.
Yes. And maybe I'll just add, Rob. I think Guy's team has done a great job of eking out further capacity and throughput opportunity. I would say, the real juice from here on is -- aside from the additional work that can be done and capitalizing on this light/heavy issue is these additional expansion projects. They are low cost. They require very little in the way of regulatory -- major regulatory permitting and so cost effective for the producers. So those are the ones that we're going to be moving on, and that's probably where the real upside is from here.
Our next question comes from the line of Dennis Coleman of Bank of America Merrill Lynch.
I have just a couple. One, can you give us a little bit of a update on what's going on with the Sabal Trail situation? I know there was a flurry of activity right in the first week of February. But what outcomes are we looking for and in what timing?
Yes. Sure. Dennis, it's Bill. So just to catch up, I think everyone knows the project went into service back in July. It remains commercially operational. Court ruled back in August that FERC didn't assess the downstream greenhouse gas issue that was the Sierra Club contention. And then FERC has since then issued a supplemental environmental impact statement that it does address the downstream GHG issue and basically concluded that there weren't any material downstream effects. So what we expect from this point forward is FERC to issue a new revised certificate shortly, perhaps within a month. And that should basically eliminate any of the issues.
So then you would expect the court to vacate the decision? Or that should eliminate the court case?
That's right. Yes, I think when FERC issues a revised certificate, it would have to be rechallenged. It would basically end the current challenge situation.
I see, I see. Okay. Very good. And then maybe can you just give a little update on the gas company amalgamation. Any update there to be had?
It's a good question, Dennis. So we've put through our initial application and that would include not just the amalgamation, but the initial rate application. The Ontario Energy Board has gone through that. It's now been setting the time line. At this point, it looks like we would have a decision sometime in Q3, potentially beginning of Q4. That's our best handicapping of it. Of course, the overall goal is to move that along so that customers can see benefits. And we're hoping that the rates would be effective as of January 1, 2019. That's the current status.
Our next question is from the line of Praneeth Satish of Wells Fargo.
Just 2 quick tax questions. On the SEP side, my understanding is that the $860 million noncash charge tied to tax reform, that could grow over time until there is a rate case. Do you have a sense for how much that liability could increase year-over-year in 2019?
It's modest over that period. There won't be -- there wouldn't be a huge amount and not probably anything that would impact our guidance.
Okay. And then just a follow-up question is on the EEP side. It doesn't look like the MLP took a noncash charge similar to SEP. Just curious why that's the case.
It's an interesting one. It's an accounting nuance. But the EEP toll structure, when combined with the Canadian Mainline under the international joint tolling arrangement, when you look at it through an accounting lens, effectively that's a negotiated structure and a negotiated agreement. So therefore, it doesn't have that, if you like, potential liability associated with it. So when we went through it with the accountants and the auditors, that's the conclusion that we came up with. It's a little nuance of how EEP is tolled.
Yes. Basically, it's a negotiated rate.
Thank you. And we have reached our time limit and are now able to -- and no longer able to take any further questions. I would like to turn the call back to Jonathan Gould for closing comments.
Yes. Thank you, Amanda. That was a -- as Al said, there was a lot ground to cover, and we even went a bit over time there. But as always, our IR team will be available right away to take any additional follow-ups that people may have. So as a reminder, contacts are myself for Enbridge Inc.-related matters; Nafeesa Kassam for Enbridge Income Fund; and Roni Cappadonna for all Spectra Energy Partners- and Enbridge Energy Partners-related follow-ups. So thank you, everyone, for your time and interest in the Enbridge Group of companies, and have a great day.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for your participation. You may now disconnect.