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Welcome to the Enbridge Inc., Enbridge Income Fund Holdings, Enbridge Energy Partners and Spectra Energy Partners First Quarter 2018 Financial Results Conference Call. My name is Sabrina, and I will be your operator for today's call. [Operator Instructions] Please note, this conference is being recorded. I would now turn the call over to Jonathan Gould, Director of Investor Relations. Jonathan, you may begin.
Thank you, Sabrina. Good morning, and welcome to Enbridge Inc. and Sponsored Vehicles Joint First Quarter 2018 Earnings Call. With me this morning are Al Monaco, President and CEO of Enbridge; John Whelen, EVP and Chief Financial Officer, Guy Jarvis, EVP and President of Liquids Pipeline; Bill Yardley, EVP and President of Gas Transmission and Midstream; And Vern Yu, EVP and Chief Development Officer.Our joint call will, again, include discussions for all of the Enbridge entities. This allows us to provide a consistent enterprise-wide strategic and financial perspective while at the same time leaving in specific commentary on the strategy and performance of each of the Sponsored Vehicles. Note that we've developed supplemental information for each vehicle to ensure that we continue to provide full and transparent disclosure. Some of this information is appended to the presentation here today and has been posted to the various company websites.And as per usual, the call is webcast, and I encourage those listening on the phone line to follow along with the supporting slides. A reply and podcast of the call will be available later today, and transcript will be posted to the website shortly thereafter.In terms of the Q&A, given the broad agenda and limited time 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 to keeping the call to roughly an hour and may not be able to get to everybody. [Operator Instructions]But as always, our Investor Relations team will be available for your more detailed and modeling specific follow-up questions afterwards. Before we begin, I'll point out that we will refer to forward-looking information on today's call. 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. Slide 2 includes a summary of these that could affect Enbridge and its affiliates and are discussed more fully in our public disclosure filings available on both the SEDAR and EDGAR system. So with that out of the way, I'll now turn the call over to Al Monaco.
Okay. Good morning, everyone. Three general topics today. I'm going to begin with an overview of the great progress we've made on executing the key priorities that we rolled out as part of our 3-year plan in December. I'll then provide some high-level comments on the first quarter results followed by our business update. John will take you through the financial results including our Sponsored Vehicles and a recent FERC policy announcement.Before I do that, I'd like to provide a 1-year postclosing assessment of the Spectra transaction.In short, we're realizing the benefits of the deal, and we're very pleased. The strategy behind it was to broaden the asset mix, geographic footprint and the growth opportunities from what is a very strong liquids pipeline franchise to a diversified North American energy infrastructure business. Natural gas and transmission and utilities now make up the majority of the assets, and we've done that without changing the value proposition. And they are delivering strong and highly predictable cash flows as we thought. First quarter numbers confirm the deal is delivering shareholder benefit. When we announced the deal, we expected it to be accretive in the first full year, and that's what's happening now. Quarterly DCF per share and EPS are up 33% and 44% year-over-year. Granted Q1 last year was noisy, but even adjusting for that, the results are very strong. Right out of the gate, we went after synergies hard, and we're ahead of the 60% we targeted for year 1. We now think there's upside to that target, and we fully expect to exceed it. Also driving accretion is the $12 billion of assets we've put into service last year, about half of that from our new gas and utility businesses.I've heard the comment that somehow the Spectra acquisition stretched our balance sheet, which isn't the case. In fact, it's the opposite. It was an all-stock transaction, so no incremental debt. In fact, the deal enhanced our credit metrics and overall credit profile. Commercially, we're benefiting from the larger footprint I mentioned with almost $5 billion of new growth projects identified, the bulk of which have been on the gas side. In sum, we're very pleased with the deal, which is playing out as expected and even a bit better. Let me now focus on the progress on our 3-year plan. That's on Slide 5. Overall, we've had a strong start to the year, and we're ahead of the schedule we had on our key priorities. Operating performance was very solid and our systems ran safety and reliability and at record throughput. That translated into strong results that are in line with our '18 guidance, and that's an important market for us this year. Yesterday we announced asset sales that exceed our $3 billion target for '18, which we set at the time. And I'm going to speak a little bit more about that later. On the financing front, we're ahead of schedule as well. With the asset sales financing progress and with our expected financial performance, we're on our way to hitting our targeted debt-to-EBITDA of 5x by the end of the year. There's $7 billion worth of projects for in-service this year and the program is going well. We passed an important milestone for the Line 3 replacement regulatory process in Minnesota. We'll talk more about that one later as well.Finally, we haven't taken our eye off future growth, and there are a couple of new projects advancing. So that's a big picture progress. So now let me get into some of those points in more depth.Q1 results were strong and a bit ahead of expectations. Earnings and cash flows are both up significantly on the absolute basis as Q1 last year reflected only 1-month of Spectra. Net earnings and DCF per share results were also up very nicely year-over-year. The liquids mainline system ran at record throughput, and the gas transmission systems also ran at peak. Utility businesses continues to deliver strong performance, and I think it's an underappreciated aspect of our predictability and strength. The strong start gives us confidence in meeting the 2018 targets. John will get into more detail on this and the rest of the financial. On now to the next slide and 2 recently announced asset sales. When we rolled out the 3-year plan, we talked about moving to a pure regulated pipeline utility asset mix. And we identified over $10 billion of assets that didn't fit with that model. To move that priority along quickly, we set a $3 billion asset target to be completed this year and that would also support the goal to accelerate deleveraging and build financial flexibility. So yesterday, as you know, we announced the sales of the Midcoast GMP assets to ArcLight for USD 1.1 billion. It's about CAD 1.4 billion. We went through a full auction process here. And the assets are being sold en bloc to ArcLight, who is getting our GMP operating and commercial team as part of the deal. Transaction subject to normal HSR review and expected to close in Q3.On the second transaction, which is on the next slide, we're selling a 49% interest in a large portion of our renewable power assets to the Canadian Pension Plan Investment Board. We're very pleased to have completed this deal. It gets us above the $3 billion target and CPPIB is a very strong financial partner. The deal includes all of our Canadian renewable assets, 2 U.S. assets as well as a 49% interest in our 610-megawatt 50%-owned German offshore project, which is slated to come into service in early 2020. The proceeds are $1.75 billion and CPP will fund its go-forward share of construction costs on the German project and the related expansion to that, which reduces about $500 million in equity requirements and brings their investment to $2.25 billion, So also positive from a financing perspective.More broadly, these 2 assets demonstrate our commitment to disciplined capital allocation. Let me expand on that point in the next slide here. Although these 2 deals achieved the $3 billion target, we've said all along we'll capitalize on good valuations for the remaining $7 billion or so of noncore assets. The noncore asset sale process that we established at the beginning of the year gives us a lot of flexibility to move on opportunities depending on the valuations we see. And on that, we're seeing a lot of interest in good valuations. Good example is where we're getting a lot of inbound interest is on the Canadian GMP assets, in whole or in part. Based on what we've seen to this point, we could move on additional asset sales, which would create added flexible -- flexibility on financial side without materially impacting our 3-year DCF per share guidance. And that added flex could be used to turn off the DRIP earlier than we planned, given where our share price is trading right now. The bottom line is that given the strong asset market, we'll look to expand our asset program if we see good value. And to clarify, regardless of whether we execute assets above the $3 billion, we still expect to achieve our target credit metrics in 2018. Moving to Slide 10, I'd like to comment on the significant progress on the funding plan. John will get into this later, of course. Recall our 3-year plan included $4 billion of hybrid issuances this year, which, as you recall, get 50% equity treatment from rating agencies and they are an effective -- cost-effective and flexible source of equity for us. Our approach was to get after this to derisk the funding plan. And just 4 months into the year, we've raised $3.1 billion or about 80% of the target. And we don't see an issue being able to complete the rest, given the options and strong demand in various markets and markets, frankly, that we even -- haven't even tapped yet. Let me switch gears now to our business update beginning with Line 3. This is obviously an important project, so I'm going to spend a few minutes on this one. In Canada, we have 40% of the pipe in the ground, and we're readying our crews for the 2018 construction season, later in the summer. In Wisconsin, we've completed the work there. It wasn't the big segment, but we've tied in that piece as well. As you know, in Minnesota, the administrative law judge issued a report on the replacement. And just as a reminder, this is a nonbinding recommendation that the ALJ provides to the PUC. Yesterday, we filed our response to the ALJ report and I encourage you to read it. And let me just capture for a few key points now though. Important to remember why we're doing this project, and why it's been approved by every other jurisdiction as we proposed. The project needs to be done because it replaces an existing line with brand-new modernized infrastructure, just like is done everywhere else with roads, bridges, transmission lines, et cetera, in any form of transportation for that matter. It also provides critical supply to U.S. consumers and that is in everybody's interest. The ALJ report clearly acknowledges those factors and the need to replace the line. So that was a very good outcome. But by now, you know we disagree with the ALJ's recommended route, which would require an in-trench replacement on the existing right-of-way, which in our view introduces safety, environmental, cultural and economic risk. We designed the project and our route based on a very extensive assessment of a number of alternatives and with very extensive consultation as well with all communities. Our route avoids environmentally sensitive areas, population centers that have grown since our existing lines were built and importantly, tribal nations. You can see from the chart here, our route was designed to respect the tribal reservations while the ALJ route seems to ignore that.And the ALJ is at odds with the environmental impact statement prepared by the Minnesota Department of Commerce, which is a very thorough piece of work. We reproduced a critical part of the table here from the FEIS, which clearly shows the ALJ route elevates risk.We can't understand, frankly, how our preferred route was not recommended by the ALJ when it's clear that our route is less impactful based on the criteria set out in the EIS. Not only that, the Department of Commerce said in the EIS, that the ALJ's route may be the least favorable route in terms of potentially affected resources.Finally, the ALJ route seems to ignore the impacts to consumers from shutting down Line 3 for 9 to 12 months or perhaps more. And surely shutting down 400,000 barrels a day is in nobody's interest, including the people of Minnesota who would be affected by higher gasoline prices. And just yesterday, by the way, in response to the ALJ report, a major refinery in Minnesota said this would significantly exacerbate a portion at far beyond current levels and put crude supply to refiners at even greater risk.Finally, as a reminder, we've got tremendous support for the project in Minnesota. Congressmen and State Legislators, right-of-way counties and cities, and the you can see on the chart there, the multitude of counties and cities that support the project. Consumers and refiners, farmers, landowners, workers and some chambers of commerce and citizen coalitions.So in summary, we believe our proposed route is the optimal solution here. We're optimistic that the PUC will see things the same way and will improve the replacement of the Line 3 as currently designed when they hold their hearing later in June.Now imagine you are saying to yourselves that all sounds good, but what's the plan if the PUC affirms the ALJ recommendation. So let me just address that directly.We think our project is clearly the best project, and we continue to expect the PUC will confirm our route. If that's not the case, then we'll reevaluate at the time the PUC makes their decision.Onto Slide 12 and the remainder of the project inventory. Our 2018 to '20 capital program is about $22 billion in scope, and we're making good headway on it. We're expecting to bring the $7 billion of projects into service this year, not quite the same load as we had last year. So far, we've completed just under $1 billion, including Stampede offshore oil lateral and a couple of projects within our T-North natural gas system in B.C. that enhanced the throughput on that network, which is much needed.The larger projects and services in '18 are more weighted for the back half of the year. On Slide 13, a couple of updates on those projects. Our NEXUS construction is underway in Michigan and Ohio, and we're about 20% done overall there. So we're still expecting to be in service in Q3.By the way, Bill and his team are very focused on doing a top-notch job here, especially from an environmental and community engagement perspective. Valley Crossing in South Texas will be a critical link to serve growing gas-fired power demand in Mexico. Construction on the onshore segment is substantially complete with work underway on offshore portion of the line right now.Last, on the Rampion Offshore Wind Project in the U.K., all 116 turbines are now installed. Remember that's a 400-megawatt project, and we are now fully connected to the grid.Moving on, and an update now on some new -- of our new projects.Alliance Pipeline, as you know, is conducting an open season for 400 million cubic feet a day, growing gas and NGLs from the Montney and Duverney they need to get to the Chicago market, which is exactly what we saw when we saw strong interest in Alliance re-contracting and even more interest now with this expansion. The cost estimate is about $2 billion, but we wouldn't see the bulk of our 50% share being needed until towards the end of our 3-year plan.Second project is an opportunity with Phillips 66 and a new Permian oil export line to feed Corpus and the Freeport markets.We like this one because there's potential to further connect into our infrastructure on the Gulf Coast. So the seaway system, dock access at Freeport and Texas City. A very successful mining open season was completed and the project is going ahead. A second open season is underway to pick up additional commitments for potential upsides to the project.You've got an option to join the JV before the end of the year, so we'll be assessing progress along the way here.The Permian and South Texas regions are also big area of focus for the natural gas team. And as you can see here, our network is ideally positioned for production growth and export potential for LNG and to satisfy Mexican demand. The 2 bcf per day Gulf Coast Express, partially owned through DCP, is now fully contracted and going ahead. And we just acquired the Pomelo pipeline project that links our Texas Eastern and the Nueces hub with Valley Crossing.So again we have a great footprint in this region and the team is assessing further buildout opportunities.So with that update let me hand it over to John for the Q1 results.
Well, thanks, Al. And Good morning, everyone. I'll pick up here on Slide 15 with a review of consolidated performance for the quarter, drilling down into the key drivers of EBITDA growth for each of our operating segments. And as you can see, and as Al already mentioned, we're off to a very good start. Consolidated adjusted EBITDA was up about $1.2 billion for the quarter. As expected a large part of the increase was driven by contributions from the new natural gas liquids pipelines and utilities assets we acquired in Spectra transaction, which closed at the end of February last year. Our first quarter results reflect a full 3 months of earnings and cash flow from the legacy Spectra assets, whereas the comparable quarter last year only included 1-month of Spectra results. But that said, the big year-over-year uplift also reflected the very strong performance from our base business, including the impact of the $12 billion of new organic growth projects that we brought into service over the balance of 2017.So starting with the Liquids Pipelines, our adjusted EBITDA was up a little over $300 million over Q1 of last year. Here the growth was primarily driven by a few factors. Firstly, strong performance on the Mainline system, which is driven by higher volumes, higher tolls and a higher average foreign -- rate on foreign exchange hedges used to convert U.S. dollar toll revenue on the Canadian Mainline as we rolled into new hedges, at rates closer to levels in the spot market.Secondly, the impact of contributions of regional oil sands projects that were placed into service in the latter part of 2017 and the impact of a full quarter of contributions from the Express-Platte system, we acquired through the Spectra transaction.And finally, strong U.S. Gulf Coast demand for crude from the mid-continent region, which resulted in higher spot shipments on both the Flanagan South and Seaway Pipelines and more than offset the impact of take-or-pay contract relief granted as a result of upstream heavy crude apportionment.Moving down the slide. Gas transmission and midstream was up significantly, as you would expect when compared to the first quarter 2017. Period-over-period growth reflects both contributions from legacy Spectra's operating assets as well as the impact of expansion projects brought online during 2017, primarily on the Texas Eastern and Algonquin systems. The cold winter across the U.S. resulted in stronger contributions from the GTM segment as a whole, with the Alliance Pipeline, in particular, benefiting from increased volumes and higher rates on winter seasonal capacity, offset to a degree by weaker volumes and processing margins on our Midcoast assets.Turning to Gas Distribution. Adjusted EBITDA increased by $265 million quarter-over-quarter. This increase was driven primarily by incremental contributions from Union Gas, we acquired in the Spectra merger. But the year-over-year improvement also reflected growth in the underlying asset base of EGD, systems expansion on the Union system as well as the impact of weather. Weather for the first quarter of this year was only slightly warmer than normal compared with the last year when weather was significantly warmer than normal resulting in an uptick in reported quarter-over-quarter performance.Green Power was up as well, about $38 million on a quarter-over-quarter basis reflecting strong wind and solar resources, the settlement of equipment performance claims, a full quarter of contributions from the Chapman Ranch and New Creek facilities and initial contributions from the Rampion Offshore project in the U.K.Energy Services increased by about $26 million. This improvement was partly the result of widening crude and NGL location differentials, which provided an opportunity to lock in attractive margins and optimize capacity obligations, but was mostly driven by the impact of colder than normal weather, which provided an opportunity to capitalize on natural gas basis differentials during the quarter.While we think there will likely continue to be opportunities to generate attractive margins within energy services on both the gas and liquids side. At this stage, we don't expect to replicate this quarter's very strong performance over the remainder of the year.Finally, turning to Elimination and Other. Recall this is the segment where we booked settlements associated with our corporate FX hedging program. These gains and losses serve to partially offset corresponding FX translation losses and gains that are captured in the EBITDA reported by those business segments that had US dollar investments. The year-over-year improvement of about $14 million in E&O this year is primarily due to lower hedge settlement losses, which resulted from both a stronger Canadian dollar and more favorable hedge rates. So all in all, a strong quarter, which positions us very well heading into the remainder of the year. The strong uptick in EBITDA also translated into solid year-over-year growth and bottom line cash flow.Turning to Slide 16. You can see the distributable cash flow was up approximately $1.1 billion, relative to the first quarter of last year. The big increase in cash flow was largely driven by the strong business performance, I just walked through, but there were some notable variances below the EBITDA line. Interest expense, current income taxes, distributions to noncontrolling interests and preferred share dividends were all higher quarter-over-quarter, primarily due to the impact of the Spectra acquisition. Notably, maintenance capital expenditures for the first quarter were actually slightly lower than Q1 of last year. This is primarily a matter of timing, as certain planned maintenance activity is shifted out until later in the year.As Al already mentioned, DCF per share for the first quarter came in at $1.37, up over 33% when compared to the first quarter of 2017. This big increase clearly reflects the strong performance from our base business, 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. The very high rate of growth on a per share basis is to some degree, a reflection of the timing of the merger closing in the first quarter of last year and the lower-than-planned O&A expense and maintenance capital spending in the first quarter of 2018, which will catch up over the course of the year. But that said, we expected a good portion of the strength we saw in our underlying businesses in the first quarter should carry through into subsequent quarters, setting us up well heading into the rest of the year.And with that in mind, on Slide 17, let's turn to the outlook and where we stand relative to the guidance provided back in December of last year.First off, as Al already noted, we're on track to deliver DCF within our previously announced guidance range of between $4.15 and $4.45 per share. While the quarter was strong, it was bolstered to a degree by the deferred spending, I just noted, and some other benefits that may not carry through the entire year. So at this early stage, we're not suggesting any changes to our estimates or projected EBITDA in each of the segments, other than to account for a shift in how we allocate cost to segments. Originally when we set out our guidance, we had planned to change our practice and allocate the hedge settlement amounts to the business segments. However, for a number of reasons, including analyst feedback, we decided not to pursue this change. So for segments, which have U.S. operations, you'll continue to see the impact of movements in the spot FX rate from quarter-to-quarter, which will be partly offset by gains or losses, as the case may be, on hedge settlements picked up down below in Eliminations and Others.The impact of this change on our EBITDA projections for each operating segment and for E&O is shown on the chart. To be clear, this change has no bearing on bottom line consolidated adjusted EBITDA, and our full year estimate remains unchanged from what we provided at Enbridge Day. At Enbridge Day, we also pointed out that our EBITDA and DCF profile is not evenly generated throughout the year, mostly due to the seasonality of our utility business as well as other items, which may not have a linear relationship quarter-over-quarter such as the timing of maintenance capital expenditures or the timing of capital project in-service dates. Given some of the delay in expenditures in the first quarter and some other puts and takes, the expected quarterly profile of projected EBITDA and DCF for the year shifted a little as you can see in the charts on the right-hand side of the slide.Before moving on to the performance of our Sponsored Vehicles, I'd be remiss not to acknowledge the FERC's announced policy change, which, if implemented, will deny MLP the ability to recover a tax allowance in their rates or tolls for the cost of service regulated pipelines. As we disclosed back on March 16, after the policy change was announced, each of our Sponsored Vehicles is affected differently. But the combined impact on Enbridge, as a whole, is not expected to be material to our results of operations or cash flows over the 2018 to 2020 horizon. And as you'll be aware, there are a number of aspects of the FERC policy that require clarification. And the policy change itself is being challenged directly by many MLPs, including ours, and by industry associations. Our MLPs may also seek mitigation through applicable regulatory processes and other solutions. As I go through the results for the quarter for our Sponsored Vehicles, I'll briefly touch on the impact of the FERC decision on the outlook for each of them, and you can find further details in the news releases and MD&As for each vehicle.So I'm now turning to Slide 18, which highlights the performance of Spectra Energy Partners, or SEP, where ongoing EBITDA and ongoing DCF were up sharply over 2017 on a quarter-over-quarter basis. The story here continues to be similar to recent quarters. Very strong steady performance from base assets and a big contribution from $2 billion of accretive organic growth projects placed into service over the course of 2017. SEP increased its distribution by $0.0125 per unit this quarter which translated into an increase of approximately 7% relative to the first quarter of 2017. And it is expected to continue to grow its dividend at the same rate each quarter through the end of the year.The FERC policy decision is not expected to have an impact on SEP in 2018, and we believe that any future impacts would be substantially mitigated through rate cases that would address a whole variety of costs that are not currently incorporated in rates. That said, any potential impacts beyond 2018 are dependent upon the success of mitigation efforts, including the execution of a rate case and our challenges to the FERC policy.As noted on this slide, we estimate the unmitigated impact to SEP's DCF to be approximately $110 million to $125 million per year, which is inclusive of an assumed disallowance for income taxes, but does not include the impact of a potential payback of accumulated deferred income tax given the uncertainty on how this will apply in practice until the FERC completes their NOI process.So turning now to Enbridge Energy Partners on Slide 19. EEP continues to deliver steady results, a reflection of its lower risk business model post the restructuring we completed in the second quarter of last year. Adjusted EBITDA was up relative to the first quarter of 2017, in large part, due to the contribution of the partnership's interest in the Bakken Pipeline System, which was placed into service in June 2017. These positive results were partially offset by the impact of lower tax rates as a result of U.S. tax reform, which resulted in a formulaic reduction in revenue on certain expansion projects whose tolls are based on a facility surcharge mechanism, or FSM, that incorporates a tax allowance in the determination of revenue requirement.The FERC policy change will also have a further impact on revenues and distributable cash flow at EEP, as the complete elimination of the tax allowance would further reduce the revenue requirement that can be recovered through the FSM toll mechanism.EEP has estimated that the impact of the complete elimination of the tax allowance on its FSM tolls would be around $125 million on bottom line DCF in 2018, exclusive of the impact of any potential adjustments for repayment evaded, which, as I said, are subject to the outcome of the FERC NOI process and further guidance from the FERC.Each DCF guidance and distribution coverage of about 1x for 2018 takes into account this estimate. Like SEP, the impact on EEP's distributable cash flow and distribution coverage beyond 2018 will in part be dependent on the success of challenges to the FERC policy and other mitigation that it pursues.The FERC's policy announcement has clearly impacted valuations of many MLPs and their sponsors. It's fair to say that at today's valuations EEP and SEP are currently -- not currently cost-effective funding vehicles for the Enbridge Group. Both the EEP and SEP have challenged and are seeking clarity on the FERC order, and we're assessing a variety of regulatory and other options to address the impact of the policy change, if implemented as announced.Any such options will need to be in the long-term interest of Enbridge shareholders and MLP unitholders.So finally, turning to Slide 20 and highlights for ENF and the Fund Group. Fund Group DCF was up sharply, posted $269 million from Q1 2017. The increase was driven primarily by higher throughput and a higher residual benchmark toll in the Canadian liquids Mainline, along with a higher effective exchange rate on hedges used to convert U.S. dollar toll revenue. Also contributing to higher Fund Group DCF was the impact of a full quarter's contribution from the new regional oil sands pipeline that were placed into service last year and strong performance from Alliance Pipeline, which saw increased demand for seasonal firm and interruptible service due to colder than average weather in the U.S. Midwest.Under the IJT mechanism on the Mainline system, any reductions in the EEP toll will create an offsetting toll revenue increase in the fund. The impact of the reduction in U.S. tax rates on EEP's FSM toll at the end of the year resulted in increased revenue and DCF at the fund during the first quarter, which will continue. Similarly, if EEP is unable to mitigate the impact of the FERC policy change when it's FSM tolls are next reset, the FERC's revenue and DCF could be positively impacted. As ENF announced earlier today, while it is still earlier in the year, this strong performance in the first quarter combined with the indirect benefits from the impact of the U.S. tax reform on EEP's tolls suggests that the fund should generate full year DCF closer to the upper end or originally announced guidance range.I wanted to briefly touch on funding before turning it back to Al. And as you can see on Slide 21, we continued to make a very good progress executing the funding plan that we rolled out last December. 4 months into the year, we've already raised a very significant portion of the total capital identified in the plan for issuance in 2018. As Al mentioned earlier, this included approximately $3.1 billion of hybrid securities, which we successfully placed in both institutional and retail markets in the United States and Canada during the quarter. And we're continuing to see appetite for these securities from a number of different markets, both private and public, in North America and globally.We continue to enjoy very strong access to senior debt capital markets, having refinanced and trimmed out close to $3 billion worth of asset-level debt at Texas Eastern and Sabal Trail since the beginning of the year in accordance with our plan. Both these deals were priced tightly and very well taken up by the market. And as already discussed, we've already hit our target for asset sales in 2018 and have the potential to do more if we get comfortable with the value we can realize.With the strong progress on both fundraising and asset sales early in 2018, the remainder of our secured capital program is very manageable. All of the remaining equity funding can be readily met through hybrid equity offerings and common equity issued through the DRIP program. We continue to make progress on deleveraging and are on track to achieve our long-term credit metric of 5x debt-to-EBITDA by year-end. Accelerating asset sales and/or increasing hybrid issuance may allow us to turn off the DRIP earlier than planned, but we're keeping a very close eye on our credit metrics when evaluating those options.So all in all, we're very pleased with the results of this quarter, and the significant progress we've made on the funding plan already this year.With that, I'll turn it back to Al to wrap up
Okay. Thanks John. Thank you. We showed these 5 strategic priorities at Enbridge Day in December when we rolled out the 3-year plan. So this is a bit of a revisit and recap here. We strongly believe that this is the right plan that will set us up for continued success going forward. As we've talked about today, we've gotten off to a great start in Q1, with the financings, asset sales, project execution, new business development and importantly delivering strong DCF per share growth. And in the big picture, '18 should be a very strong year year-over-year. Overall, we're very pleased with the quarter. We've made good progress and execution will continue to be our focus in 2018. And with that, I'll hand it back over to the operator to get to the Q&A session.
[Operator Instructions] Jeremy Tonet from JPMorgan is on the line with a question.
Just had a question on the Line 3 replacement. And I apologize if this is a simple question, or if I'm missing the obvious here. But with regards to the process, this being State regulated, is there anything precluding you from going to kind of a federal process under the ICA? Apologize if I'm missing something obvious here.
Well, I think currently the focus is seeking Minnesota approvals. I don't think -- at this time we continue to be confident in the process in Minnesota. It's been very thorough. The evidence that's on the record and related testimony as it relates to the statutes of the PUC will be evaluating our project under, we think give us a high degree of confidence. Of course, we are all aware of the Interstate Commerce Act existence, but it's not something that we're actively evaluating in the context of where we're at with Line 3.
Yes, I'll take -- Jeremy, it's Al here. That was Guy. Pretty clearly here this is State authority. So I think in any different scenario is in the category of, I guess, assessing in the long term. But really that's the way we're looking at it. It's a State project.
Got you. And news reports indicate that you guys have some pretty significant interest out there for additional asset sales and some sizable price tags have been put out there in the media. I guess, could you expand a bit more there as far as what you're seeing in the marketplace? And is the interest really robust and the valuation strong? And that's something that really appeals to you right now? And if so, if you're able to execute on that, does that mean less hybrid issuances? Or would you go for kind of lower leverage or any other thoughts that you can share there?
Well, there is a couple of things in there. So let me go to your last part first. I think the whole premise of this, if the opportunities arise to do more asset sales is to give us flexibility. And as I mentioned in my comments, that could be to turn off the DRIP. Synergon mentions that as well. So I think it's really there to give us financial flexibility. And obviously those assets are in that category for a reason. We are moving to a pure pipeline, utility model. So from that perspective if we can get through that in quicker fashion, while getting good valuations, then that's what we would do. To be honest, I'm not sure where these reports come from sometimes. But I would say the essence of them is correct in that we're seeing very, very strong interest. You saw that with the couple of asset sales we had and moved on those quickly, got good valuations. And we're seeing a carry-on interest, let's just call it that, on the other assets we have in that category. So we're optimistic actually that we could see some pretty good values there. And if we do see them, then we'll move on it.
And the next question will come from the line of Robert Kwan with RBC Capital Markets.
Al, I think you had kind of touched on, at least from the asset sale perspective. But taking a step back when you look at additional funding and asset sales as well as your corporate structure, obviously there is a balance. But given some of these are competing interests, can you kind of rank order your priorities as it relates to items such as distributable cash accretion dilution, the ability to maintain the 10% dividend growth, ability to exceed your leverage targets and then as it relates to funding, achieving a self-funding model, for at least the equity portion of projects or at least being able to turn off the DRIP, as you alluded to earlier?
Okay. Well, I guess, to put it directly, Robert, clearly, we want to move towards a self-funding position. And having this asset sale inventory with very good interest would help us get us there. And obviously at the current share price, that's got to be our objective. On the dividend payout side, I think we're comfortable with the range of payout we have right now. We feel very good about growing the dividends through 2020, as you know, based on the projections that we have. So really, I think in broad terms, we're moving towards more of self-funding capability simply because of where the price is and the fact that we want to minimize the equity we put out there. And these asset sales, they give us a lot of opportunity to do that. Beyond the planning horizon, that's probably a different story. We'll have to assess where we are when we get through the 3-year plan, but those are the broad priorities through this next couple of 3 years.
I guess maybe put differently, have any of those factors become either more important or less important to you, say, since 6 months ago when you were kind of recutting the plan?
When you say these -- those factors, what are you getting at?
Just around sticking to the 10% dividend growth or exceeding your leverage targets, trying to drive more towards that self-funding model?
Right. Well, the leverage targets that we had in the plan, as you might recall, showed us getting to 5x, and then below 5x in the plan based on our projections. So that's, I guess, ultimately where the numbers we're projecting are. So conservative -- more conservative in the 5x target, I guess, is the point. And again, if we can move quickly to the self-funding, do more asset sales, that's the priority.
Okay. That's great. If I can just finish on the Mainline and guide us just probably. So can you just talk about continued optimization efforts and what you think that may or may not be able to deliver? And then any status of discussions where shippers do accelerate some of the smaller capacity enhancement initiatives that you previously discussed?
Sure, Robert. I think in terms of the optimization efforts, so you know throughout last year, we created a number of those. Some of them we utilize all the time, just given the nature of them to create more capacity. Probably the biggest one that's out there that has kind of given us the most flexibility is this ability to move additional volumes of medium blend on our system. That tool is really what we use when we start to see some weakness on the light volumes coming to our system. We have begun to experience some of that, I guess, towards the end of the first quarter and continuing on here in the spring. So we've been actively employing those optimization efforts since sometime in March, and we continue seeing to do that through the summer, which is good news for our customers, in that we could move more crude, and it's a good news for us that we keep throughputs up. In terms of the other smaller capacity addition items that are on, I think when we've talked about this in the past, our message has been, we continue to work on them. There is really nothing material or key decisions to be made until actually sometime next year related to any of those. So there is really not an engagement required with our customers at this time.
And the next question will come from the line of Robert Hope with Scotiabank.
Just want to touch on the MLPs. Have FERC's actions as well as evaluation compression at SEP and EEP altered your view of the strategic value of those assets as well as how they fit into the Enbridge story longer term? Or is there too much uncertainty with FERC's action right now?
Well, I'd say, there's a great deal -- it's John speaking, Rob. There is a great deal of uncertainty with respect to the FERC action that's going on that everybody I think is out there evaluating. But there is no doubt when you look at the valuations of MLPs generally and of our MLPs today that their effectiveness as funding vehicles for the Enbridge Group has been diminished. So as we've talked about a lot over the last number of quarters here that's something that we'll continue to evaluate and it's probably got a little more complicated in light of the FERC decision.
All right. That's helpful. And then turning attention to Line 3. If Minnesota is delayed, would you still press on with the Canadian construction and then look to recover a return on that capital through tolls? Or would you potentially slow construction there?
It's Guy. Our plan all along with the Canadian site has been to try and dovetail the completion of Canadian construction with the timing that we think we'll be able to complete Minnesota. We'll continue to evaluate that. Our plan for 2018 construction, as Al mentioned, is later in the summer. So by then we should have clarity coming out of the PUC process to understand just how aggressively we're going to press forced with that.
And the next question will come from the line of Linda Ezergailis with TD Securities.
I'm trying to understand kind of your appetite for joint ventures prospectively. And specifically, with respect to CPP, are there some sort of plans or ROFRs in place for either both partners in case someone exits. Do you see additional Enbridge assets potentially being added to that JV? And then when you look at additional asset sales, for example, in Canadian midstream, are you also contemplating similar JV structures for that?
Linda, it's Al here. I think we're going to have Vern address that question.
Hi, Linda, I think with CPP, we have an arrangement to work with them on development opportunities for offshore wind in Europe. And that's exclusively what we're doing right now. I think to answer your second question, we'll always entertainment JVs where we think we get the best economic value. But as we look at the Canadian midstream right now, we are looking that on -- looking at that for an en bloc sale.
Okay. Maybe as a follow-up we can go to some of your new project opportunities. Can you comment on the Gray Oak pipeline, what you would need to see before you would exercise your option by year-end? Would it be the outcome of the second open season? And how might you think of funding that? And maybe you can give us a sense of the size of the investment in some way?
Linda, it's Guy. So in terms of the elements that we'll be continuing to evaluate through this period that the option exists, obviously, volumes are important. It's a very competitive basin there right now. So the underpinning of the primary term contracts is important as-is as well an analysis of your re-contracting risk down the road. We also want to get more comfort with capital costs. This whole project came together very quickly and there is still some more work to do there. I think the third element, and quite important to us is, how do we make this project fit in with some of the other strategic elements that we're working on. And some of those are underway and some of them are still in idea stage. But we see an opportunity here potentially for that line to really dovetail well with some other strategic initiatives we're doing on the Liquids Pipelines side. I think the investment opportunity is rough -- in USD 500 million range. And I can't remember if there is a third question.
Funding.
Oh, on the funding. I'll turn over to John to speak to.
Yes, Linda, I think at the end of the day the ultimate equity funding required for that project is really quite modest. So I don't think it was that -- we had, if you like, a little bit of a placeholder in our plan already for smaller equity investments at the end of the day. And so I don't think it really dramatically changes our overall funding plan, if in fact, we were to pull the trigger on investment in Gray Oak.
Just my thought on this, Linda. This is a pretty strong project. I think P66 along with us in reviewing it has done a pretty good job in getting volumes together and very strong contracts. And as you saw, the project is going ahead. I think what we're talking about is a further refinement in our own thinking as to how we fit it in. Really that's the only last piece, I guess, if you will. But the project on a standalone basis is very strong even without additional commitments. And now with the first set of commitments in, good chance that we'll get more.
The next question will comes from the line of Ben Pham with BMO.
I wanted to go back to the funding asset sale, specifically. Now that you've got $3 billion announced and $7 billion is more flexibility than anything. And you've mentioned, like, good valuation achieved on $3 billion. Would you say that going forward then -- the valuations you're looking for on additional sales, you'd be wanting to get higher valuations than what you've got in the $3 billion? Or is it more just a valuation comparison to existing share price?
I think it's more of the former. I mean, yes, immediate accretion is a factor in our thinking. But really it comes down to what's the IRRs we're getting from the asset sales, and how does that compare to the whole value that we have for the assets. So it really is situation dependent. I think the good valuations that we saw here is a pretty good indication. Obviously, running through auction processes we're going to be very focused on maximizing the value. As was referred to earlier, we're seeing some very strong indications from the work we've done, so far, in the Canadian GMP assets. So we're going to be working hard to make sure that we're getting full value.
And I know this isn't just a mathematical equation, there's some nonfinancial factors to consider. But I wanted to clarify, so when you look at value, it's an IRR longer-term DCF right? I'm just looking at per share EBITDA?
Yes, absolutely. That's clearly what we look at as a priority. And then, of course, as you are referring to, the whole purpose behind the asset sales, at least one part in any way, was to ensure that we're moving to the pipeline utility model. We think there is a better overall valuation once we get through the asset sales. So we're motivated and that motivation is certainly helped along by the fact that we're seeing very good interest in these assets.
And the next question will come from the line of Ted Durbin with Goldman Sachs.
So just coming back to Line 3, I guess, I'd love to hear the different options you're thinking about if the PUC does decide to go with the ALJ recommendation of an in-trench replacement option. What are the next potential steps? I mean in my mind you could outright cancel the project, which seems like a low probability. You can move forward with that recommendation. You could fight it in courtroom. Just trying to think about the different scenarios of how this could play out, please?
Ted, it's Guy. We're really not spending any time looking at those options right now. When people talk about other options versus our preferred route and project, we evaluated all of those 5 years ago, and we determined that our project and our route was the most optimal solution for Minnesota and the other jurisdictions in which we're conducting the project. So we believe, as I said earlier, that the evidence and the testimony that's in front of the PUC should lead them to approve what we've got. We're not speculating about other actions that they might take. And when we know what the PUC decision is in June, we'll be looking at whatever we need to at that time.
Okay. And then if I could just turn to the asset sales, could you give us the EBITDA from the assets that were sold on a trailing 12-month basis or -- and for the first quarter between Midcoast and renewables?
It's Vern. I think what we've been telling people is on the renewables, the sale equates to about a low double-digit EBITDA multiple. And then on Midcoast, it equates to a high single-digit EBITDA multiple. I think that's based on our outlook for the next full year run rate. I don't think the trailing multiples are generally indicative of value of the asset.
Okay. Great. And then if I could sneak one more in. Just coming back to SEP and the mitigation impacts that you might be able to make from the $110 million to $125 million that you mentioned, I guess, talk to us about the [ TEDCO ] and the potential for rate case there, what -- how much underearning you're going to be showing is kind of, I guess, what you're implying in that comment when you filed some of these -- the 501-G form and whatnot?
Hey, Ted, it's Bill Yardley. Probably don't want to get into any specifics on mitigation. Think about Texas Eastern where we're 28 years removed from our last rate case. So we got an awful lot of things changed over the course of that period of time. And it probably just wouldn't be a good idea for me to go into too much detail on what the moving parts might be, especially in advance of having these discussions with the customers. But suffice to say, there are plenty of things that we -- that have changed over the course of time, not the least of which is the rate base increases that were seen with new integrity rules, emissions requirements, et cetera. So I'd kind of like to leave that there.
And the next question comes from the line of Robert Catellier with CIBC Capital Markets.
Both of my questions here are going to be follow-ups to subjects that you've already touched on. But on Line 3 specifically, I'm just wondering if you are compelled under the consent decree to move forward with the project in some shape or form irrespective of whether you agree with the routing decision? Or are there other options that -- under which you might not pursue an in-trench replacement?
Well, again, as we said earlier, our plan right now is the pursuit and approval of our preferred project. The consent decree does have us -- of course, the consent decree can't compel us to do something we can get approval to do. So we've got a project in there that we're seeking approval for. We'll see if that project gets approved or not. We think it will. In the event that we're in a position where the time frame in which we have -- it takes us to get it replaced. We have an obligation to continue to demonstrate under the consent decree that we are -- can safely manage and operate the existing Line 3, and that's exactly what we'll do.
I hate to keep going back to this. And maybe we sounded like broken records. But the one thing about the ALJ recommendation is, it was pretty clear that the line -- that they agreed the line needed to be replaced, from the perspective of modernizing infrastructure, from the perspective of making sure that we're the safest possible. That was pretty clear. And the second part, as we've highlighted in the information and, again, I encourage you to read what we filed on this, it's also very clear in our minds that this is the right route from the perspective of the environment, from the perspective of tribal nations, from the perspective of minimizing safety concerns and finally, economics. So we keep coming back to it. But that is really the base case here. And we'll assess if we see something different from the PUC.
Just in terms of simplification. Obviously, this was a priority before the FERC actions. But it obviously, that's muddied the waters a little bit. So I'm wondering what level of clarity you think you need before you reevaluate simplification processes or next steps? In other words, do you need full clarity on the deferred income tax issue in addition to just the tax allowance issue and the various regulatory strategies you have? Or do you need that full level of clarity before you can consider any transactions?
Rob, it's John. More clarity would be great, but there is a whole bunch of different factors effectively that we're looking at as we evaluate this including the reaction of the market generally and where these things are being valued. So yes, we look to see clarity. But it doesn't mean we're going to get it absolutely. There's lots of things that will factor into our decision and the timing of anything that we do.
The next question comes from the line of Matthew Taylor with Tudor, Pickering, Holt & Co.
Just looking at potential maintenance or replacement on other parts of the crude system, can you just give us a quick update on the evaluation of the potential replacement or work on Line 10? And then maybe also an update on Line 5?
So it's Guy. In terms of Line 10, the segment replacement work was completed within the last month or 2, and has been placed into service. So that's done. In terms of Line 5, our work with the State of Michigan on various elements of that agreement we entered into in the second half of last year is all on track. There have been no conclusions reached yet. But the obligation we have under that is to start finalizing some of that work as early as the middle of June, and we're on track to meet those targets.
And that's great. And then one last one. Just on Alliance, is there any ability to bring cost or the corresponding toll down? Is there any flex on there, or should we just look at the $2 billion and just kind of wait for the results of the binding open season?
You answered your own question. I think we've got a few weeks to wait for the open season to close. And then we'll be doing a fair amount of work on scope, and we will have new cost estimates after we see that.
The next question comes from the line of Elvira Scotto with RBC Capital Markets.
This is actually Edson on for Elvira. Could you comment on the motivation behind growing the distribution at SEP, especially in the context of increased uncertainty given the FERC announcement in March?
Yes, again -- it's John, again, commenting here. We had made a projection of growing that distribution by a $0.0125 for quarter through '18, as Bill has already alluded to. I think we have a number of different mitigating impacts that we could ultimately pursue at the end of the day. Those are -- there are uncertainties with respect to the FERC implementation and so on. But those are down the road a little bit further. And so I think for 2018, we're pretty comfortable with that. We think it has plenty of flexibility, and the increment of those increases is very, very modest. So the balance sheet effect of that in any event is not large. I think at this stage we're comfortable with that. We reassess as we look forward going into the future, however.
Yes, I think -- just I'll make a comment here, too. What he says is spot on. '18, we're very confident. And when you look beyond 2018, that's really going to depend on the effectiveness of mitigation which we're going to have to wait for a bit to see how that unfolds.
Very helpful. And just shifting gears real quick. Do you have any thoughts you could share on the potential provision to C Corp at SEP?
It's John again. I'd say that's getting a little bit too down into the weeds of this particular stage. That's an option that I'm sure many MLPs are evaluating, and how they might do that and where they might do that. But I'd say, at this stage, it's sort of all part of the mix at this stage. Very situational specific to between different entities even within our group.
Looks like we've got a couple of more, then we'll try and bring it in.
And the next question comes from the line of Dennis Coleman with Bank of America.
Just a couple of quick ones. Can you remind us please on the budget for Line 3 replacement? How much is just the Minnesota portion? Do you -- have you broken that out?
I don't believe I have the Minnesota portion right at the tip of my fingers. I think the number that does ring in my bell is that the U.S. portion, which is -- the bulk of which is Minnesota I think is USD 2.9 billion.
I think that's right because if you think about it, it really just cuts through North Dakota minimally and in Wisconsin you've got something like 13 or 14 miles. So that's probably the bulk of it there.
Okay. And then totally switching gears here. But the Gas Distribution business had a very strong quarter certainly compared to last year, particularly the EGD piece, where it looks like a lot of that is weather-related. I wonder if you might just give a little bit of color there in terms of how we should think about it. Is it weather-related? I know you're still a little bit warmer than forecast or the average heating degree days, but how should we think about this quarter as a go forward?
Yes. A couple of things there, Dennis. The -- it's actually a combination of things, as I said on the call. There is some weather because weather was a lot warmer than normal, which would be embedded in rates last year where it was only slightly warmer than normal for the first quarter of this year. But there were a bunch of other factors as well, including the impact of just rate base growth, the inherent growth built into EGD's customer [ IR ] and the projects that Union was doing as well. So those are factors. I'd say of the total amount related to weather, if you're looking actual-over-actual quarter-over-quarter, that was in the range of $25 million of the total amount that you saw there. The -- and looking forward, I think we're just slightly behind related to whether like maybe $5 million at the end of March, but frankly, we had a very cold April than on in. So actually weather if anything is a bit of a -- a little bit of a tailwind on the Gas Distribution business heading into the back half of the year.
The next question is from the line of Patrick Kenny with National Bank Financial.
Just to clean up the what if scenarios on Line 3. And probably a question for Guy. But when looking at your post 2020 unsecured growth opportunities within liquids, just wondering if you could walk us through how much of the $5 billion to $10 billion bucket that was shown back in Enbridge Day, what type of projects, how much potential capital would not be contingent on Line 3 being replaced?
Yes, I think probably the bigger issue in relation to the magnitude of capital that would be available kind of on the Mainline and for adding additional volumes is going to be the situation with competing pipelines. Line 3 does help bolster some of those options. Others do not require Line 3. So I think I want to say that of that 5 kind of 1.5 to 2 was potential that we could see across the Mainline. And as I said earlier, some of that will not be impacted by Line 3 somewhat.
Okay. And then for John as it relates to achieving that 10% dividend growth guidance through 2020, again, I know Line 3 is in your base plan to support that level of growth. But I guess, if that capital is delayed and your leverage is already below 5x, would you say that, that gives you flexibility to let the payout ratio move up a little bit in order to sustain 10% dividend growth, or would you look to decelerate dividend growth just to keep a ceiling on the near-term payout ratio?
I think we'd be paying close attention to the payout ratio, Patrick, at the end of the day. So I think the answer is probably no. We've got some flexibility generally on the balance sheet. I've already talked about we're driving well below our target metrics as you get out in 2020 under the plan we have right now. So but I would say, no, we probably will be careful not to let that dividend payout creep up.
We have reached our time limit, and we are not able to take any further questions at this time. I will now turn the call over to Jonathan Gould for final remarks.
Thank you, Sabrina. That was -- again, a lot of ground to cover in an hour and, again, we've gone a little bit overtime. But as always our IR team will be available right way to take any additional follow-ups that people may have. So as a reminder, contacts are myself for Enbridge Inc.-related matters; and Nafeesa Kassam for Enbridge Income Fund; and Roni Cappadonna for all Spectra Energy Partners and Enbridge Energy Partners-related follow-ups. So thanks everyone for your time and interest in Enbridge, and have a great day.
Thank you, ladies and gentlemen. This does conclude today's conference. Thank you for participating. You may now disconnect.