Enbridge Inc.
Q4 2014 Earnings Call Transcript

Published: 20 Feb 2015

Operator:

Good morning, ladies and gentlemen, and welcome to the Enbridge Incorporated 2014 yearend financial results conference call. I would now like to turn the meeting over to Adam McKnight, Director of Investor Relations.
Adam McKnight:

Thank you, John. Good morning, and welcome to Enbridge Inc.'s 2014 yearend and fourth quarter earnings call. With me this morning are Al Monaco, President and CEO; John Whelen, Executive Vice President and Chief Financial Officer; Guy Jarvis, President, Liquids Pipelines; Leigh Kelln, Vice President, Investor Relations and Enterprise Risk; and Chris Johnston, Vice President and Controller. This call is webcast, and I encourage those listening on the phone lines to view the supporting slides, which are available on our website. A replay and podcast of the call will be available later today, and a transcript will be posted to our website shortly thereafter. The Q&A format will be the same as always. We'll take questions from the analyst community first, and then invite questions from the media. I would ask that for everyone's benefit, you wait until the end of the call, to queue up for questions, and the questions are limited to two per person. Please reenter the queue, if you have additional queries. I would also remind you that Leigh and I will be available after the call for any follow-up questions that you might have. Before we begin, I'd like to point out that we will refer to forward-looking information in connection with Enbridge and the subject matter of today's call. By its nature, this information contains forecasts, assumptions, and expectations about future outcomes. So we remind you it is subject to the risks and uncertainties affecting every business, including ours. This slide includes the summary of the significant factors and risks that could affect future outcomes for Enbridge, which are also discussed more fully in our public disclosure filings available on both the SEDAR and EDGAR systems. With that, I'll now turn the call over to Al Monaco.
Albert Monaco:

Thanks, Adam. As you can tell from the agenda, we've got a few things to cover off this morning. I'm going to lead-off with the highlights, including the recent developments, and then the progress we've made on our strategic priorities. Those priorities are going to generate strong growth for Enbridge, but they're also very well aligned with our customers in a very tough environment. John, will provide color on the financial results, update you on our 2015 outlook and our usual funding plan status. Given the changes in crude oil prices since our last call, Guy Jarvis will take you through the implications for our Liquids Pipelines business, which is well-positioned for the future as you'll see. I'll wrap up the call with the two main value drivers for Enbridge through 2018 and beyond, those being the secured capital program and our recently announced financial optimization plan and the resulting growth outlook. So moving now to Slide 4. Because we have more than the usual to talk about today, I'm going to begin with the main messages that we'll be expanding on today. The key takeaway is that in the current business environment, our reliable business model provides a true safe haven for investors, but importantly without giving up growth and strong returns. Low oil prices will impact some of our businesses. These are expected to be modest overall, leading us at the same 2015 EPS guidance range of $2.05 to $2.35 per share. Next our exceptional five-year growth is driven by a $34 billion program of attractive, secured and infrastructure investments and this program remains firm. Over the past year we had great success with our capacity optimization initiatives and in opening up new markets, both of which support good producer netbacks relative to the past and provide reliable feedstock for refiners. And I'll show you a very telling chart on the optimization progress. With Flanagan South and Seaway train now in service and the recent NEB decision on Line 9, we have provided our shippers with 1.3 million barrels per day of low cost access to attractive new markets, with another 400,000 barrels per day on track for completion this year. These are very good accomplishments in a tough permitting and regulatory environment. On top of that, and something that will provide transparency on today, our prospects for developing even more market access solutions for our shippers are very solid. On the drawing board right now, are a variety of lost bolt-on type opportunities to expand or extend our pipeline system per shippers. And as Guy will go through, these can provide market access for Canadian and Bakken producers to attractive North American markets in the low-cost phase steps. These low cost options are effective at anytime, but more so, when you've got a low crude oil price environment and a low basis differential environment on top of that, like we're in today. Last takeaway, the earnings and cash flow from our current growth investment program remain on track to deliver great value for investors. And later on top of that, the financial structure, we announced in December, will further enhance value and that will help us win new opportunities that can extend our industry-leading growth rate. So those are the big messages. Now, let's get into these points, beginning with Slide 5. Now, this morning or I guess yesterday, we announced our 2014 adjusted earnings, just shy of $1.6 billion or $1.90 a share, with the puts and takes we discussed through last year that brings us well within our guidance range. The results came in pretty much as expected and we talked about that on our third quarter call, and from here we're on track to deliver an expected average annual EPS growth rate of 10% to 12% for 2013 through 2018, as set out at Enbridge Day back in October. John is going to cover more detail on the results. But before that, I'd like to preview the progress on strategic priorities. We're on the Slide 6. First, Enbridge has a long track record of delivering regular annual dividend growth, going back two decades now. Over last five years, dividend growth averaged 14% per year. On March 2, our shareholders will see the first quarterly dividend at our new $1.86 per share annual rate, a substantial 33% increase. This material jump reflects the combination of factors that all boil down to the strength of our core business model, strong operating performance and confidence in our growth outlook. Now to Slide 7, and something that's critical to us, that being our number one priority, which continues to be the safety and reliability of our systems, because that is in fact what enables everything else that we do. I'm very pleased with the progress on our way to industry leadership. We're getting there by executing our five-year operational risk management plan, that's the six areas that you see in the chart. And the chart on the bottom left shows we've gone through the most intensive phase of our maintenance and integrity program, employing not just $5 billion roughly in capital, but the latest in technology. Even that underestimates the progress we have made, because it doesn't include major investments. The full replacement of Line B, between Chicago and Sarnia; a major refurbishment of Line 9 from Sarnia to Montreal; and we've agreed with our shippers on replacement of Line 3 from Hardisty all the way to Superior, Wisconsin. All this moves us toward even greater system reliability, which supports not only the important role we play in meeting North American energy requirements, but it's also good for our customers. Moving to Slide 8. One of our biggest accomplishments, and one that I am most proud of for the team, is optimizing the capacity on our Liquids Pipelines. There are many logistical factors that prevent achieving what we refer to as nameplate capacity, that's not unusual in our business to clearly given the complexity of our system. A couple of years ago, with the illuming tightness in x Alberta capacity, we began working hard to optimize the system. This effort has generated 340,000 barrels per day of improvement in effective available capacity, providing more low-cost pipeline service for customers and obviously increasing revenues for us. We're going to continue to make ground this year, up to 2.2 million barrels per day, with another 100,000 in the works after that. And potentially another 100,000 beyond that is possible with some further investment. Moving now to Slide 9, which is along the same lines. When we saw the Alberta Clipper expansion permit was going to be delayed, we moved quickly to find some workarounds. We were successful in that and gained another 100,000 barrels per day or so from temporary optimizations, and there is upside to that, if we need it. These will remain in place pending completion of the Alberta Clipper expansion permitting process. So when you combine the initiatives on the previous slide we just talked about with these temporary workarounds, we're able to move record volumes on our mainline across the border of over 2.2 million barrels per day in December and then again in January. So record volumes on the system. We're now on to Slide 10. As you all know the current environment for executing pipeline projects is challenging to say the least. That's why we're very pleased with the $10 billion of projects we put into service last year combined that came in very close to budget, which is no small feat these days. We're also progressing well on the remaining $24 billion in execution, which are scheduled to come into service through 2018 and those are tracking close to budget as well. In a few cases, we're seeing target completion date slip, because of the regulatory and permitting delays. That's just a fact of life in this climate. As we've explained with Line 9 and even Flanagan South, that results in some delays in the earnings contributions, but overall we are getting these projects done. Also critical to execution is funding the capital program, as you see here on the right, we've made good progress again last year raising $10 billion enterprise-wide. Moving to Slide 11, I'd like to highlight what this success means for our customers and our industry. Enbridge is making a big dent in the need for new market access by connecting supply first and foremost to North American coastal markets, markets that attract global prices. This slide shows the expansions and extensions of our system that will open up the 1.7 million barrels per day of new markets by managing our way through this regulatory and permitting environment. Something that we're very pleased with this is startup of Flanagan South and the Seaway Twin, which establishes the first large-scale full-path solution for heavy crude from Western Canada to the Gulf Coast. Even though, absolute prices have come down dramatically, it's clear that opening up this market has improved the relative price of Canadian heavy barrels. After Line 9 is flowing crude, we'll have 1.3 million of the 1.7 million up and running, with the remaining 400,000 on track for completion later this year. Now, the inset chart here shows the cost of moving a heavy barrel from Western Canada to Chicago. By maintaining a tight hold on costs, we're delivering very competitive tolls that were established under our CTS agreement. In fact, if you look at the growth rate there, it's just over 1% per year over this period, so very efficient from a cost perspective. That's critical to ensuring our customers have low-cost reliable access to a multitude of refineries in the PADD II and now the PADD III market. On to the next slide, I mentioned Line 9. So let me provide you an update on that. As you know, following the approval of the project last year, the NEB did a very detailed assessment of the conditions that we needed to satisfy. I am pleased that a couple of weeks ago, the NEB gave us the go-ahead to apply for what they refer to as, leave to open in our business, which we have now done. We are now waiting approval for that leave to open. Our best estimate now is that Line will go into service during the second quarter. This again is a very important milestone for the company and we believe for producers and Eastern Canadian refiners. Line 9 allows refiners in Ontario and Quebec to access reliable feedstock and get themselves off foreign crude and producers gain access to a new market. In the bigger picture, this new source to supply for Eastern refiners will enhance their competitiveness and protect thousands of Canadian refinery jobs. Another priority of ours is to extend and diversify our sources of growth. And Slide 13 shows how our inventory of secured growth has increased over the last year. Going back at the time, the $29 billion we started with at the beginning of the last year, seem like it might have been the peak. That proved not to be the case. If fact, we added another $9 billion, which more than replaced the $5 billion that went into service in 2013. Moving to Slide 14 now. As you know, we've always been focused on optimizing our cost of capital, but even more so in the last 18 months or so by improving the effectiveness of our two sponsored investments, Enbridge Income Fund and Enbridge Energy Partners or EEP. On EEP, we've undertaken various initiatives over that period to improve its ability to accept dropdowns from Enbridge. The slide recounts the most active year we've had for sponsored vehicle dropdowns, totaling nearly $3 billion with drops to both Enbridge Income Fund and EEP. These two drops boost the distribution growth of both vehicles, while providing an attractive source of funding to Enbridge. And they've established a very solid foundation for the expanded dropdown strategy we've embarked on. And you can see what I mean by that on Slide 15. The slide shows a marked improvement in both ENF and EEP, which is great to see. EEP's yield improved by over 200 basis points and the revised incentive distribution structure that we implemented, positions EEP very well for growth going forward. Enbridge Income Fund Holdings started with a more competitive yield, but has also improved nicely. Both vehicles are now positioned to play a big role in Enbridge's financial strategy going forward. I'll come back to the financial optimization involving EIF and potentially EEP a little later. For now though, it's over to John for the financial review section. Then Guy will pick it up from there with some further thoughts on the Liquids Pipelines business and the environment that we're in today.
John Whelen:

Well, thanks, Al, and good morning everyone. I'm picking up on Slide 16 with a more granular look at our 2014 financial performance by segment. Consolidated adjusted earnings for the full year came in at just under $1.6 billion. That's up by close to 10% over last year's record earnings and reflects the strong underlying growth inherent in our core businesses, led this year by our Liquids Pipelines and sponsored vehicle segments. Liquids Pipelines performance over the full year was very strong. Adjusted earnings from this segment were about $88 million, close to 11%, higher than 2013, largely on the strength of record volume throughput on the Canadian Mainline, driven by growing supply from Western Canada and strong refinery demand. Earnings were further bolstered by new assets coming into service on the regional oil sands systems and the startup of Flanagan South in the fourth quarter, as well as effective cost management. Deliveries on the mainline ex-Gretna reached a record 2.2 million barrels in December, and have continued to be strong thus far in the New Year. Adjusted earnings for the quarter did come in slightly lower than the fourth quarter of last year, as the impact of higher volumes in the Canadian Mainline were offset by a lower IJT Residual Benchmark Toll and higher power costs for that particular period. The quarter-over-quarter picture was also distorted by a one-time catch up in revenue on our regional oil sand system that we recorded in the fourth quarter's 2013, and also the absence of revenue from Line 9. Earnings from gas distribution came in just a touch higher than last year, both for the quarter and the full year. This was very much in line with anticipated performance under the utilities new customized incentive ratemaking methodology, which is approved by the OEB last year and is expected to generate very solid earnings growth this year on the strength of a growing capital base and ongoing management and efficiency initiatives. Fourth quarter earnings from gas pipelines, processing and Energy Services were up a little over the fourth quarter of last year, largely on the strength of greater marketing upside opportunities in Energy Services and higher contribution from our Canadian midstream businesses. However, on a full year basis, earnings from this segment were lower by about $67 million when compared to last year for a number of reasons. Firstly, full year earnings from Energy Services were down following a very strong 2013, due to narrowing of location differentials and less favorable conditions in certain markets access by committed transportation capacity where we do incur demand charges. Secondly, Aux Sable performance was down due to weaker frac margins, which reduced upside sharing revenue. And lastly, the overall segment performance was affected in the fourth quarter by the sale of Enbridge's 50% interest in the U.S. portion of the Alliance Pipeline to Enbridge Income Fund, with of course a corresponding uptick in the quarterly earnings being reflected in our sponsored vehicle segment. On the other hand, earnings generated from our sponsored investments were up sharply, growing $34 million quarter-over-quarter and a $116 million for the full year. This very strong growth in this segment is again a reflection of a number of factors. Enbridge Energy Partners delivered higher earnings contribution in incentive income on the strength of record throughput and higher tolls on the Lakehead Mainline system and higher utilization to expand the North Dakota system, all of which more than offset weaker results in the partnerships natural gas gathering and processing business. Enbridge also benefited from its direct investment in major expansion projects on the Lakehead Mainline that came into service during the year. Recall that Enbridge Inc. owns a 75% interest in Eastern Access expansion project and held a 67% interest in the Alberta Clipper expansion until the end of the year, through the joint funding arrangements that we have in place with EEP. And finally, Enbridge benefited from a higher pickup of earnings and incentive distributions from Enbridge Income Fund, which saw improved performance from its Liquids Pipelines and Storage segment and benefited from the dropdown of the Alliance U.S. Pipeline and an interest in the Southern Lights Pipeline in the fourth quarter that I referred to a moment ago. Rounding out the numbers, the corporate segment was a little stronger than last year, for both the quarter and the full year, as net interest margin recorded in the corporate segment more than offset higher preferred share dividends. So all-in-all a very strong year, notwithstanding a few puts and takes in different businesses and significant volatility elsewhere in the energy sector. In this challenging environment, our ability to deliver reliable and predictable earnings and cash flow, year in and year out, is very much predicated on our business model, which is underpinned by a number of key principles. And I'm now on Slide 17. We invest in assets that are supported by strong long-term supply and demand fundamentals. We enhance the reliability and the earnings of the cash flow stream from those assets through conservative commercial structure, which deliver predictable earnings and protect against downside risk. We have a disciplined investment review process that focuses on ensuring investment opportunities aligned very closely with our business model and earn attractive returns on a risk adjusted basis. We focus on on-time, on-budget projects executions for those projects that do meet our investment criteria. And of course, we have very conservative and prudent financial policies, which limit exposure to non-controllable risks, and ensure we have sufficient funding flexibilities to deliver on our growth plans, regardless of market conditions. You can see the results in the chart on the upper right hand side of this slide, which shows that we have consistently delivered adjusted EPS within our announced guidance range, even through significant periods of commodity and financial market volatility. We believe that this reliability and predictability has translated directly into the consistent and superior returns we have generated for our shareholders from year-to-year and over the long run, regardless of market cycles. So moving on to Slide 18. Given this commodity price volatility that we've seen of late, it's important to emphasize the key elements of our business model that gives us the confidence in our earnings and cash flow outlook. Supply and demand fundamentals for our pipelines continue to be strong. In a challenging commodity price environment, low cost access to key markets is vitally important to our customers. Demand for export capacity has never been higher and our Mainline Liquids Pipelines system continues to be under apportionment. In addition, we have taken care to structure our commercial arrangements in ways to provide against a declining volume scenario if that were to arise. By way of example, the recently negotiated toll surcharge for the Line 3 Replacement Program, our largest infrastructure project ever, will ratchet up in the event volumes fall below defined thresholds. Most of our other upstream and downstream infrastructure is tolled on either take-or-pay basis or some form of cost of service charge, which protects against volume fluctuations. Our earnings are primarily derived from fees charged for energy delivery services. We look to avoid direct commodity price exposure in our businesses. Where residual exposure does exist, we seek to closely manage that risk through disciplined hedging programs. So even in periods of significant commodity price volatility, the impact on our overall earnings and cash flow should be really quite well contained. And with that in mind, I'm going to move on to a quick assessment on how 2015 shaping up so far. And now looking at Slide 19. So given the reliable nature of our business model and our assessment of the fundamentals, we do continue to feel comfortable, as Al said, with our guidance range of $2.05 to $2.35 per share that we provided in December. This is of course a status quo projection and does not include the impact of the proposed restructuring that we did announce in December as well. While it's very early in the year, we do see a few emerging headwinds and tailwinds. Firstly, while we're certainly very pleased to apply for the leave to open the elongated approval process for Line 9, means that the startup and commencement of revenue collection on that line will slip into the second quarter later than we expected at the time of our guidance call, and that is creating a little bit of an earnings headwind. With the extreme decline in crude oil prices in the latter half of 2014, we're also seeing a little downward pressure on earnings in the few business lines, where we had commodity price sensitivity. Prospects, for example, for upside sharing at Aux Sable are weaker, given the impact of falling crude prices have had on NGL prices and frac spreads, and contributions from our Energy Services business are also expected to come in a little under expectations. However, these headwinds are substantially being offset by an expectation of lower borrowing cost over the balance of year and an uplift from the portion of our projected U.S. dollar earnings that are not hedged. Operation and administrative expense also represents potential upside. So again, it's early days, but headwinds and tailwinds would appear to be reasonably matched at this point. So moving along to Slide 20 now, just to reiterate some points that Al made. In 2014, we did raise a record $10 billion in permanent capital from a variety of different markets, and bolstered our enterprise-wide credit facilities by a little over $0.5 billion. As Al mentioned earlier, we successfully completed two significant dropdown transactions, monetizing assets on attractive terms and importantly creating additional equity capacity on our corporate balance sheet to support ongoing growth. As you can see on the right-hand side of this slide, we have about $9 billion of available liquidity, which provides us with ample capacity and flexibility. So finally, and turning now to Slide 21 and coming back to our longer-term funding plans, you can see we're depicting our updated sources and uses over a five-year period in that waterfall format that we have been presenting for a number of years now. It assumes that the restructuring transaction proceeds as envisioned and presents a combined picture, which includes the requirements and plan funding for both Enbridge Inc. and Enbridge Income Fund. And you can see from the slide that we really have made good inroads on our longer-term funding plan with the capital we raised and the dropdown transactions we completed in 2014. We have already raised more than $7 billion of debt and we have also made very good progress on the equity side. Looking forward, post restructuring, we would expect Enbridge Income Fund Holdings to raise something in the range of $3 billion of the required equity over the balance of the planning horizon to fund the growth inherent in its acquired businesses, with Enbridge, Inc. fund in the balance. Of course, the exact split will vary, depending on the Income Fund Holdings' relative valuation and the market appetite for its equity. That leaves about $1.5 billion in equity for Enbridge, Inc. to raise over the remainder of the planning horizon, which we believe can be readily filled through a combination of further issuances of preferred shares and potentially additional asset dropdowns to EEP. And with that, I'm going to turn the call over to Guy, to talk a little bit more about the fundamentals.
Guy Jarvis:

Thanks, John. Good morning, everybody. I'll pick up on Slide 22 and cover a few perspectives on the current crude price environment and the longer-term implications for our Liquids Pipelines business. As John has already covered, we don't see much impact at all in the near-term. Longer-term, we think the following slides highlight how our mainline system continues to be really well-positioned across a range of oil price scenarios; and has the flexibility to continue to competitively expand to meet the needs of our customers, be it on a smaller volume incremental basis or a larger volume solution that includes additional new market access. So let me start with oil prices. Most forecasters think we could see further weakness in the second quarter, but after that, a gradually improving trend in the global balance between demand growth and supply, with a recovery in price to about $80 WTI by 2017 to 2018, and further gradual increases thereafter. We think this is a reasonable base case and reflects the way most of our larger shippers seem to be looking at the world. As a pipeline business, the point-to-point location differentials are as important to us as the absolute level of Brent or WTI. This chart shows current basis differentials, and the table contrast those with the peak over the last year. The decline we have experienced in crude prices over the last six months has also significantly compressed regional price disparities. One implication of the narrowing differentials is that supplementing pipeline shipments with rail shipments is resulting in the lowest netback prices. We're seeing fewer volumes moving on rail and back on to pipes, particularly in the Bakken. I'll talk a bit more about rail in a minute. We should see a gradual expansion of differentials in parallel with the partial recovery of absolute prices, getting back to a level sufficient to support large scale projects to the two Canadian coasts. However, we don't see the differentials expanding enough to support much rail volume in the longer-term, even though it will still provide producers with a backstop. Given the strategic positioning, cost effectiveness and the newly opened up markets that Al talked about earlier, there is still enough margin increase to make movements to the U.S. Gulf Coast and to Eastern Canada, attractive to our shippers, even if they weren't contractually obligated to ship or pay. Equally important, current differentials are also wide enough to position low-cost expansions of our system, as an attractive option for shippers, including potentially an extension to the Eastern Gulf Coast, which we still have on the drawing boards. I'll come back to this later. Slide 23 moves to some Western Canada supply outlook perspectives. The blue area is CAPP's 2014 forecast, with the red-dash line being the downward adjustment they made in January to 2015 and 2016. What happens to the forecast profile beyond 2016, probably not much, if industry thinking remains centered on a scenario along the lines of the price outlook I alluded to earlier, which should be economic for most oil sands developments. Certainly, when we look at the projects included in our own 2014 supply forecast, which was similar to CAPPs, we had already risked out all those that would be questionable in an $80 WTI environment. None of the recent announcements of deferrals have affected our own internal risk supply forecast. The amounts indicated in the inset box are the announced production from projects, which are fully underway at present and will drive the near-to-medium term trend in supply. However, there are other possible scenarios, which we and our shippers will need to consider. The yellow line is a plausible alternative, with a larger near-term deceleration of supply growth and is much as a 0.5 million barrels less production by the mid-2020s. This scenario will be consistent with a more immediate response to current prices, probably in terms of conventional production and the adoption of a more pessimistic view of the longer-term prices, resulting in some deferrals of projects that would otherwise have been built into the risked forecast beginning in 2018 and on. We'll talk about what that would mean to us in a few minutes. To translate the supply outlook into what it means for pipeline throughput, we need to spend a minute on how rail factors into the equation. The left side of Slide 24 depicts various point-to-point rail costs based on work undertaken by CAPP. The bottomline is that rail will tend to be the swing mode, even with differentials widening back out again somewhat. Rail reflects up as required, unless and until pipeline capacity is available, and then will tend to swing down, as that capacity does become available. This behavior is depicted in the charts on the right-hand side for both Western Canada and the Bakken. In Western Canada, we expect rail volume to expand for a few years, with the pipeline capacity remains apportioned, but then disappears as the large new export projects come into service at the end of the decade. If the lower supply scenario, we just looked at, were to prevail, the near-term impact would be just less rail, while the pipes would remain full. A similar picture applies to the Bakken, where rail should also shrink to minimal levels by the end of the decade. That brings us to the implications for throughput on our mainline, and I am on Slide 25. In our base case, which is the green line, and which we discussed at Enbridge Day, Keystone XL is in-service in 2019; and Energy East plus one of the two West Coast projects is in-service in 2020. In this scenario, we are currently chock-a-block full and we remain full, as we bring on the two phases of Alberta Clipper expansion capacity; and as we squeeze the last bit of capacity availability out of our system, leaving about 200,000 barrels a day of capacity that we can't get at, due to upstream bottlenecks and crude slate versus line allocations. In almost any near-term supply scenario, this picture should stay the same with rail flexing up or down to balance supply changes. The blue line reflects the specific alternative scenario we discussed a few minutes ago, and assuming the same new export pipeline still proceed with only a one-year delay to either the West Coast or Energy East. In this scenario, we will see a drop in throughput available for 200,000 barrels per day in 2021, the final year of our current seedment. After that, we will either be back on cost of service or under a renegotiated CTS, which would take into consideration the throughput outlook at that time. So we don't expect that the current oil price environment will have much effect on us at all in the near and medium-term and likely little effect in the longer-term as well. In fact this is actually a conservative portrayal and that we assume three of the four new pipelines go ahead and are in service by 2020. As I bring my comments to a close, Slide 26 really pulls the picture together of the further market access options involving low-cost expansion and extension opportunities on our mainline system, which will be exploring with our shippers. It depicts a number of opportunities we have to increase market access by a further 0.5 million barrels per day or more by a combination of expansion of existing market access initiatives, in particular the Flanagan South Seaway system to move additional heavy volumes to the U.S. Gulf Coast; and Line 9, as and when needed to move additional light barrels to Montreal to satisfy the remaining needs of the Quebec refineries. And new initiatives, such as utilization of existing repurposed infrastructure to connect Flanagan to the Eastern Gulf Coast. The slide also shows expansion opportunities required to feed the additional market access initiatives both, upstream of Superior and downstream. All of these involve relatively small low cost bolt-on projects that can be staged in increments as required to meet shipper needs. For that reason, we think that they will be attractive in a lower price, lower supply scenario, or even just in the face of greater uncertainty about oil prices. With all of that, I will now pass it back to Al.
Albert Monaco:

Thanks, Guy. And as you can see, there is a lot of embedded growth within our large Liquids Pipelines strategic footprint. Back to the broader picture, there are two main drivers of our earnings and dividend growth for Enbridge coming off. The first is our $44 billion growth capital program, the largest in our history. And as we discussed $34 billion of that, or just over three quarters is commercially secured, on track, and very solid. This $34 billion provides nearly all of the 10% to 12% EPS growth that I referred to earlier. We've allowed for another $10 billion in our funding plan, which we're working on, but not yet secured. Between the Liquids Pipelines opportunities that Guy has touched on, and our plans to expand gas and power, we see filling in this next $10 billion as probable. This chunk of investment opportunity falls mostly on to the backend of our five-year plan horizon, so it contributes to post-2018 growth. Also kicking in post-2018 area will be the tilted return profile from the secured projects that are nearly, will almost all be in service by the end of 2017. So moving now on to Slide 28. The slide recaps, the projects that we expect will go into service this year, some $9 billion. Most of you are familiar with that inventory, so I'm not going to go through that. As you can, it will be another big year for liquids, but we're also working hard on other areas, being gas pipelines, gas distribution and power generation. That brings me to the second earnings and dividend growth driver on the next slide. The financial structure of our optimization plan, we announced in December. Now, as a reminder, here in a nutshell is what this is all about. Our capital investment plan provides investors with a truly exceptional level of highly visible and reliable growth. The objective of the optimization plan is to increase the value of that program. Basically the restructuring focus is on the way we fund the Canadian Liquids Pipelines component of our growth, where most of the equity funding would come from the public investors in Enbridge Income Fund. The other part of the optimization is the increase to our dividend payout rate and a plan to increase that payout further, as we move beyond the peak funding requirements in our five-year capital plan. And we posted to the IR section of the website actually today, a backgrounder that takes you through this concept in a bit more detail. The next slide here provides the high-level summary of the expected results. The chart illustrates that the optimization plan is a win-win for shareholders of both Enbridge and Enbridge Income Fund Holdings. For Enbridge, moving the Canadian Liquids Pipelines assets down to the fund, doesn't change the fact that it will remain as our largest and core business. In fact, that was the case if you think back to 1991, when our U.S. Mainline assets were moved to EEP. We are going to maintain a very significant economic interest in this business, continue to operate it, and we'll manage the strategic development of that business, so Enbridge will look fundamentally the same. Our shareholders benefit from what we expect would be about a 10% EPS accretion from the dropdown, the ultimate result, of course, will depend on the terms that we finalize with the fund's independent committee. We've talked about the 33% dividend increase, which reflects the EPS uplift from the drop and the shift in payout policy. The optimization plan also includes further payout increases supporting a 14% to 16% dividend growth rate at least through 2018. And the plan reduces our equity funding requirement by about $1 billion over the period. And because we still retain about an 80% economic interest in the fund by 2018, the structure positions us to release more capital for redeployment or increase dividends beyond that as well. Moving to the right here, the benefits to Enbridge Income Fund Holdings and its public shareholders will also be substantial. Unlike Enbridge though, the fund will be completely transformed from this dropdown. We'll still be a high payout vehicle focused on providing a large component of its return in the form of cash distributions. But once the transaction is complete, the Income Fund will have the largest asset base among the high payout Canadian infrastructure companies, and we think the highest quality assets in terms of the underlying commercial model and resulting reliability of cash flow. And we'll also have the most visible, transparent source of growth in distributable cash flow through a very large secured organic growth program, and a strong competitive position. The magnitude of that growth is highly visible and should be the highest among its Canadian peers, in particular, with a dividend growth rate of above 10% at least through 2018. That all makes for a very appealing package and should support a premium valuation among the fund's high payout peers. Moving to the next slide. A key objective of our plan, as I described this on the last call as well, is to ensure that Enbridge Inc. the corporate parent to the group would also continue to be in attractive investment for fixed income investors. And we believe it will be. Here is why? Cash flow stream is going to be the same and well-diversified. No change in the business risk and our risk profile. We're not adding any additional leverage, whatsoever, as part of this optimization. We structured the plan, so that the enterprise-wide consolidated leverage metrics are unchanged. And actually if you look at Enbridge itself on a standalone basis, the leverage metrics improved considerably, as debt is moved down to the fund post restructuring. That's our view, but we'll continue to communicate with debt holders on this, and provide additional information that will help their assessment. And the background I referred to earlier that we posted on the website includes a bit more information on the fixed income perspective as well. On the next slide, that brings us to the EPS growth outlook from the combination of our organic growth program and our optimization plan. The little portion of this chart shows our base 10% to 12% average annual growth rate through 2018, the yellow layers on the expected 10% accretion from the optimization plan. After 2018, we expect to continue to see strong organic growth from the investment in all of our businesses, supplemented by the tilted returns I discussed earlier. That comes from the investments that are going in the ground over the next three years. Optimization benefits endure after 2018 through EIFH's continued investments in the fund. The next slide shows the corresponding dividend outlook. The optimization supports the 33% increase to be paid on March 1 compared to something like 11% with the status quo. Of this much higher base, we then expect a significant higher growth rate for the balance of the period to 2018, some 14% to 16% rather, as we expand the payout rate. The post 2018 growth rate will be driven by the same factors as we discussed on the earnings slide. So to wrap this up today and we appreciate your patience covering a lot of information today, 2014 was a year of significant progress for us, both for the year itself and in building momentum for our future. In these volatile times, our longstanding and demonstrated reliable business model provides a safe haven for investors. The beauty is that our investors don't have to sacrifice higher returns for the sake of that safety. Enbridge investors get both. That in a nutshell is our value proposition. Our record growth investment program remains solid, both commercially and with respect to execution. Although, we're in a tough oil price environment right now, we remain positive on the long-term fundamentals. Throughput on the Liquids System is expected to increase over the next few years and we're in good position, given the strategic position and competitiveness of our system. If anything, our ability to bring forward more low cost-based solutions for our customers will ensure the industry is well served in this less certain price environment. All of this adds up to exceptional earnings and dividend growth for our investors through 2018 and beyond. So with that, we will now turn it back to the operator for questions.
Operator:

[Operator Instructions] Our first question is from Paul Lechem from CIBC.
Paul Lechem:

Just with reference to the Liquids Pipeline expansion opportunities that Guy discussed, I was just wondering, can you give us a sense of what is needed for you to move forward on some of these expansion opportunities? Do you need to get better clarity into whether some competitive pipelines such as Energy East or Keystone XL get built before you would move forward on any of these? And also, are any of these projects included currently in your risk unsecured bucket, your $10 billion of unsecured projects?
Guy Jarvis:

I think the answer to the first part of your question is that, certain of the bolt-ons that we're looking at right now, we think that we will probably pursue irrespective of what's going on with some of the competing pipeline situations out in the environment. But clearly, if we were to think about a larger volume expansion, coupled with some more market access, that would a factor in the consideration with ourselves and our shippers. In terms of your question about the dollars, most of this stuff is contemplated beyond 2018. So it would not be included in the current risk capital.
Albert Monaco:

I think, Paul, just to add on there. I mean the fact that they're relatively small in size and lower-cost expansions that we can make incrementally, and in the cases, you see there mostly don't require significant new permit initiatives. We're using existing rights-of-way within the existing footprint. It's obviously, in this environment relatively easier to make those happen, even though it's still lot of work. So I would say those are more in the category of highly probable in most cases.
Paul Lechem:

Just a quick second one, if I can, to John maybe. The guidance range unchanged, but it seems a wider range than you've had in the past. You gave us some of the headwinds and tailwinds, but just wondering what do you see that could move you either to the top or bottom end of the range more dramatically, than the headwinds and tailwinds you gave us?
John Whelen:

Well, there isn't a lot actually, Paul, at the end of the day. We kind of emphasize through the call that it's a pretty stable reliable business model that we're dealing with. One of the issue is obviously the timeliness of regulatory permitting projects coming into service, so on and so forth those are some of the non-controllables that we can only asses as the year moves along as to whether that might have an impact. So I think that really that's probably the biggest one. Everything else is pretty much self-contained within the business and very definable. So we get quite comfortable, but particularly a project permitting timing is one of the bigger issues that's emerged over the last little while.
Operator:

Our next question is from Ted Durbin from Goldman Sachs.
Ted Durbin:

Can you talk a little bit about some of the projects where you have spoken about tilted returns and the range of outcomes there potentially, given where oil prices are and this alternative scenario of potentially lower volumes? Where would the returns come in, maybe say in the lower case scenarios is my question?
Albert Monaco:

There really isn't that much of variability in those circumstances that you described, lower oil prices. That is simply because the commercial structures that underpin those -- and I'll use Line 3, I think we refer to that one in the remarks also, Flanagan South and there are some others as well. The tolls are pretty much prescribed as to fit the producers' circumstances and desires that they had at the time. So I don't see a lot of variability in the tolls structure and therefore the return profile from a lower oil price environment.
Ted Durbin:

Next one for me is, just looking at honestly the really strong performance of ENF since the restructuring announcement, does that change how you are thinking about whether it's the dropdown multiple to the fund, that 13x to 15x, or about the amount of equity that you might try to do with ENF?
Albert Monaco:

I don't think so at this point. I mean, as you point out, the valuation has improved. I think that's a reflection of the things that I described earlier as to the benefits of ENF in terms of this transformation that we'll under go. So I don't think we see a significant change at this point to the parameters we outlined. Certainly as it progresses and demonstrates its capability, we've always said that $600 million to $800 million that we've assumed it could raise, that could change, but that's our planning assumption at this point, and that really hasn't changed at this point so far.
Operator:

Next question is from Robert Kwan from RBC Capital Markets.
Robert Kwan:

I guess, just on the restructuring. The markets had some time to react to this. So just wondering first on the equity side, your thoughts on how your stock and ENF have traded versus your expectations going into the announcement? And then on the fixed income side, any commentary on credit spreads? It looks like you have addressed a little bit in the presentation, but as well reference rates have dropped, so anything that you have done to try to lock in some of those lower reference rates on your unhedged or previously unhedged exposures?
Albert Monaco:

I'll respond to the first one, then I'll hand it to John on the credit spreads. Robert, I think it's pretty much lined up as we thought coming out after the announcement. I think clearly, the income front has performed well for the reasons we described. Obviously, we think there is probably some more upside there as we move towards the transaction and executed, so I'd say there is certainly some room on the Income Fund from here, at least that's our view. On the Enbridge side, probably it hasn't been as much reflected that we would like, and certainly the dividend payout has helped that, but I think as we move, as I said, closer to execution in midyear that we should see some full reflection of the power between these two vehicles that we outlined in the remarks. John?
John Whelen:

So maybe picking up on the credit side, Robert. You're right, a fall in benchmark rates, it will have an impact, because there is certainly a portion of our plant financing, which isn't hedged, but there is a large piece of it that is hedged. So we're relatively indifferent there. We've seen widening of credit spreads across the energy sector, quite frankly. But to be fair, you're right, ours have widened probably a little bit more than average after the announcement of the project, in part because we're in the situation here where we're still defining the terms and proposing the transaction. And we need to and we'll certainly be getting out with more detail to our fixed income investors, and we're working closely of course with the credit rating agencies as well. So at the end of the day, I think we're comfortable, certainly where we are with the transaction. We've got some work to do on the debt side, as we always knew we did to see us through the execution.
Robert Kwan:

And John, so have you done anything to lock-in the lower government bond rates just to improve the economics?
John Whelen:

We are in a continuous mode of monitoring our interest rate exposures all the way through. So we're kind of always in hedge mode. At the end of the day managing that, and of course, you do get opportunities when you see falling benchmark rates like this. So we'll continue to watch that carefully and there is an active program that's ongoing.
Robert Kwan:

And just my second question, I think this is for Guy. You mentioned 2.2 million barrels a day x Gretna in December and then into January. It's I think 2.07 million average for the quarter. So I'm just wondering what did you see, as you moved into December and January? Was it the capacity enhancements or downstream bottlenecks being removed for things like Flanagan South, their Bakken flows or I guess I'm just trying to look at how sustainable do you see the 2.2 million being, as we go forward through the year?
Guy Jarvis:

Robert, we see it has been quite sustainable and it stems from kind of the underlying response to your question. First and foremost, production is continuing to growth. As we've come into the year already, we're seeing month-over-month increases in nominations to our system. So absent the production, a lot of the other stuff doesn't matter, but the production is strong. Al alluded to all of the things. We have come a long ways in terms of more effectively managing our own system to make sure that every barrel of capacity that we have available we're filling. So there is a strong effort by our team in driving that. And we can't forget that the downstream markets have been performing really very well. We haven't had any major refinery disruptions or other upsets. And in fact, with the addition of Flanagan South now, that's a bit of another safety valve for a system in the event that we do have an on-system refinery problem, where the barrels can be redirected down Flanagan South to some extent. So our outlook is for continuing strong volumes throughout the year.
Albert Monaco:

If you look back at the chart, Robert, I think it's a very good question, because the nature of those optimizations are, despite their nature, sustainable. If you think about the integrity program, over last a little while, that's allowed us to remove some of those pressure restrictions that we had self-imposed. Certainly, the team's done a great job in scheduling the system optimally. And what I mean by that is, movements in and out of tanks, ensuring that the producers deliver in the upstream side, and that we clear tankage on the downstream as fast as we can. And then some really good thinking, I believe, on line allocations and optimizing between the lines. So all that's pretty solid and sustainable.
Operator:

Our next question is from Brian Zarahn from Barclays.
Brian Zarahn:

Appreciate your view on the puts and takes of oil prices, and I know you reiterated your guidance. But I was curious for your view, if we do have a prolonged period of low oil prices, what does that mean for your $10 billion of projects that are not yet secured?
Albert Monaco:

I think as Guy pointed out, there is a lot of opportunities here in the low oil price low differential environment. Even if it is sustained, and we don't think that will be the case, but even if it is, there are some pretty good opportunities we saw there, just given the fact that -- we're pretty confident just based on that production profile that show that we're going to need more capacity. And as you pointed out, rail is probably going to be the first two come off in the next little while. But you also have to remember, for us we've got other types of projects in that $10 billion category, around the gas side of the business, both on distribution and gas pipelines; and generation, hopefully there will be some opportunities there. We've got some international things that we'll work on. So it's pretty much diversified. Obviously, it involves risk and that's why it's in that $10 billion risk category. So it's hard to tell. We're pretty bullish long-term on the fundamentals, and maybe that's really the crux of the question here in that. The industry has certainly had a lot of experience in managing in this kind of the environment. They've got good strong balance sheets. But more importantly, the long-term demand for growth in energy from very solid outlooks on population growth, urbanization, standard living, that's all going to happen. And when you look at what's required to replace annual production, it's going to take some anywhere from $800 billion to $900 billion a year of new investments. So that investment is simply not going to happen, if oil prices are $50, and hence the self correcting mechanism that we see. So maybe that's a bit of a longer answer than you wanted. But at the end of the day we remain pretty bullish on the overall outlook for the commodities, and particularly our system, given its low cost expandability.
Brian Zarahn:

Well, I will stay tuned for the low-cost expansion projects. I guess shifting to Enbridge Energy Partners, any additional color on when you expect an announcement on the accelerated dropdown plan?
Albert Monaco:

Well, I have to say the priority right now, and the team is working extremely hard, is to get the Canadian infrastructure dropdown reviewed by the special committee. There's a lot of work to be done. They will have a long process there. So I think that's the major priority right now. But we are at the same time working on our analysis of the potential drop to the U.S. As we've said, we should have that concluded by midyear some time. So it's a very thorough process, as we went through on the Canadian side. So it's going to take some time. No more additional color on timing than that.
Operator:

Our next question is from Faisal Khan from Citigroup.
Faisal Khan:

Just on the projects in execution, the $24 billion. Can you let us know exactly, of those $24 billion, what exactly has been permitted? Just want to understand sort of the risks involved in some of these projects getting delayed. Some companies recently have been giving us sort of numbers of the projects that are actually under construction and have been permitted versus some of the delays other companies have been seeing in some of their long-dated projects.
Albert Monaco:

Well, that's a good question. I'm not sure we have that breakdown. But I would say, first of all, most of them are actually in execution. So by definition, they'd be permitted. What I mean by execution are actually in construction or at least through the design process. I guess, Sandpiper probably is one that still needs to be finalized as far as the regulatory process. That's the one that comes to mind. Line 3, I think, is still in the regulatory process. Guy, you want to help me out there?
Guy Jarvis:

Yes. So you're right around Sandpiper. That's still proceeding through the Minnesota Public Utilities Commission process. The Line 3 replacement has been filed and we were notified recently that the National Energy Board has accepted it as a complete application. So that ones in process. On the Alberta Clipper expansions, we have all of the state and provincial permits and NEB permits to proceed. We're still working with Department of State to get the Alberta Clipper Presidential Permit Amendment, which we hope to get before the end of this year.
Faisal Khan:

Those are all in '17, right? And the $14 billion you guys have outlined on, I think, Slide 27?
Guy Jarvis:

Yes. I think we're hoping to get Clipper sooner than that. But Sandpiper and Line 3 replacement, you're correct, they're further out.
Faisal Khan:

And just on the forecasted rail volumes that you guys have outlined for us through 2020. I guess, what does that assume in terms of pipelines that come online? I mean, if we get more delays in capacities, is rail just going to continue to ramp up on volumes?
Guy Jarvis:

Our assumptions on what's in-service is we have assumed that we have Alberta Clipper permit by then. Like I said, we assumed Keystone XL comes into service in the beginning of 2019 and a few pipes thereafter. I think the question around continuing delays and what happens is exactly what we are targeting with some of our bolt-on opportunities. If there is going to be an extended period of delays on the approvals of these larger opportunities, we think we have a great opportunity to take some of our expansion capabilities into those periods and move it by pipeline.
Operator:

Next question is from Carl Kirst from BMO.
Carl Kirst:

Maybe a financial question for John just to start, given the normal puts and takes that go on in periods, sort of the adjusted earnings versus GAAP. And as we begin to focus a little bit more on distributable cash flow, as you all did at the Enbridge Day with the 25% CAGR. I was wondering could you provide us distributable cash flow for full year 2014, or absent that, even just what you are looking at as kind of perhaps normalized recurring adjusted operating cash flow in addition to adjusted earnings.
John Whelen:

Carl, those are numbers that we certainly track internally. We're not reporting those numbers as yet. One of the considerations, quite frankly, as a result of the large scale restructuring and dropdown is whether we shift in fact to provide that perspective externally on a regular basis. So I think the short answer is at this stage, no, I don't have a specific number for you. Our metric is continuing for the moment as it has been, which is adjusted earnings, but it is something we do follow internally. And are looking at, with feedback, of course, from the analyst community looking at adopting going forward as part of that transition as being another metric that we track. But for now, that's not something that we're reporting.
Carl Kirst:

Understood. And obviously, as feedback, we'd certainly appreciate that in the future in conjunction.
John Whelen:

We got your feedback.
Carl Kirst:

Maybe a very small perhaps financial, perhaps operational question, but a small question on Nexus. It looks like that that is still sort of under negotiation and recognizing again very small project, but we should not perhaps take from that any reticence or reluctance to go further into the Gas Pipeline infrastructure space, be it because of delays, et cetera, correct? I mean, I assume that is just an issue of a negotiating process with your potential equity partners.
Albert Monaco:

Yes, that's exactly right, Carl. In fact, it's probably the opposite. We're very keen on the project. There is couple of very good partners there in DT and Spectra. We see life the same way in terms of the supply fundamentals in the Marcellus, Utica area, but also on the demand side from a gas utility point of view, remember as well, we have some very powerful infrastructure in that area already with Vector. And so, yes, we're very keen on it and you shouldn't take our current position as not supporting their project. We think it's very good project. And as maybe you pointing out here, in terms of our overall strategy, as we've been saying, certainly more gas infrastructure is something we're looking at very keenly and this would fit pretty much in the middle of that fairway.
Operator:

Next question is from Rob Hope from Macquarie.
Rob Hope:

Just two quick questions. Regarding acquisitions, has your dropdown strategy potentially accelerated the timing of potential acquisitions to diversify your cash flow stream?
Albert Monaco:

Well, off the bat, I think if we get to the ultimate objective here, which is a better reflection in the marketplace of our very strong growth profile, organic capital program. I think, obviously, that would put us in a better position, I guess, you'd say, in terms of being able to utilize the currency going forward. But I will say that the dropdowns are very necessary in terms of ensuring that we maximize the value of the program, but we really are not focused on any major change in our overall strategy. So the optimization I think is a very powerful tool to maximize value, but we still have the same strategies and we'll be focused on the same areas of discipline that we have in the past in terms of investments and whether they're going to add value. So it puts us in better position, but no major change in the strategy at this point.
Rob Hope:

And maybe just one follow-up. In your prepared remarks, you mentioned about reaching the Eastern Gulf Coast using existing infrastructure. Are you in discussions with the existing owners, I'm assuming one specific pipeline to reach that area?
Guy Jarvis:

Well, I think the best way I'd characterize it is, our view is that that's an attractive market and we're examining as many alternatives as we can to come up with what's likely to be the most competitive solution. Clearly, I think the one you're referring to does have a lot of attractiveness to it. So we'll just have to kind of see how it plays out.
Albert Monaco:

I think that's a good point. I mean, that's pretty important in our business is to have these options, because there're a number of reasons why certain existing infrastructure may not be able to utilize. That's why I think Guy's point is good, we've got to continuingly be looking at other ways to get to the same place, and so that's our job, and we're looking at all the alternatives.
Operator:

Our next question is from Robert Catellier from GMP Securities.
Robert Catellier:

I have one on the restructuring. But first, I wondered if you could provide a little bit more color on Alberta Clipper and your expectations for the in-service dates there? The MD&A states that the trial level decision is not expected before the third quarter, but presumably there might be an appeal by the losing party there. And if you could address my question by just discussing whether or not you're considering any accommodations for the shippers similar to what you have done on the final tranche of Line 61 to align that with the Sandpiper in-service date?
Guy Jarvis:

I'm going to try and take a crack at your question. So I think in terms of Alberta Clipper, and I think your reference to litigation, that litigation, as I recall, is not centered around our own process for achieving our presidential permit amendment. It is rather a challenge against the Department of State that somehow they did not attempt to stop the flexibility and maintenance program that we put in place last year. As Al mentioned, it is allowing us to move some of the Alberta Clipper volumes through already permitted cross-border presidential permit. So that proceeding is out there. We know about it. We've talked about it. But it is not directly having bearing on the permit process for Alberta Clipper. So I think that would be the way I would answer the first one. To go to your second point, the real issue around the timing of Southern Access up to 1.2 million barrels a day, it's not oil price related, it is regulatory process related. So Sandpiper has been delayed. We've disclosed for a number of periods now. And all we're doing is making sure we line up the downstream capacity to time with the upstream capacity. If we proceeded ahead and put that asset into service ahead of time, all we're going to be doing is driving up the toll and impacting the competitiveness for our shippers. So working on a plan to try and make sure that that doesn't' have to happen.
Albert Monaco:

And just to further point on the first area of your question around Clipper, I think the Department of State is working on the file. We understand that the environmental contractors completed their work and it's in the Department of State's hands for its review. But remember that, as we described earlier that we do have a temporary work ground, should that process be delayed. And I think that's quite critical in terms of this year's outlook for the mainline and specifically the volumes that we expect to come through.
Robert Catellier:

And just on the restructuring. Clearly, it would depend to a large extent on your cost of capital, your perceived cost of capital. But I am wondering if you view the company as being in a position to make sort of a strategic or a growth platform investment, while you still have the restructuring pending. In other words, you have your hands full trying to get the restructuring done. Would that impede you for making a larger platform acquisition or a strategic investment?
Albert Monaco:

Well, maybe the way to answer that is that at this point, our main priority is to focus on the restructuring. As I mentioned earlier, we really do need to focus on that. We've got a midyear timeline for it, that's not that far away. So I'd say that's our main priority. One of the things that I need to think about and our executive team needs to think about is making sure the organization is not stretched and that we're focused on the right things at the right time. But in addition to that, I can tell you there is nothing that we have in the hopper right now that would conflict, I guess, with the timing that we expect over the next few months around the restructuring. So that's the way I'd attack that one.
Operator:

And at this time, I would now like to invite members of the media to join the queue for questions. And our next analyst question is from Andrew Kuske from Credit Suisse.
Andrew Kuske:

I guess, the question is for John, and it just relates to your outlook on financing on the debt side, in particular when we've got a bit of a dichotomy in the interest rate outlooks across the Canada/U.S. border with the prospect for declining rates in Canada and the prospect for increasing rates in the US. Just how do you think about that from a debt financing standpoint?
John Whelen:

Well, from a debt financing standpoint, obviously, we'll actively manage the interest rate exposure. We'll manage liquidity refinancing risk as we go along. As I mentioned earlier, and it was touched on an earlier question, there's a substantial portion of our plan to debt that has already hedged in any event. So we have the benefit there being fairly selective as to when we ultimately come to market, when the appetite is there for the debt that we need to raise. So I think we'll be pretty flexible at the end of the day in terms of how we approach the market looking for the right windows of opportunity, when they exist. We're a little less driven by movements in the underlying benchmark bond rates and underlying short-term rates just because of our hedging activity.
Andrew Kuske:

And then related to the interest rates is obviously the currency. How are you thinking about your currency positioning now and then into the future? Is there going to be a substantial change from the past approach? What is your thought process on currency? Where do you think it goes?
John Whelen:

Well, again, our business model likes us to be relatively indifferent to where movements in currency take us. At the end of the day, we are relatively substantially hedged. I think we are around 80% hedged through 2015 and somewhere north of 70% hedged over the next few years over our planning horizon. So we are a little flexible in terms of where we can manage. And overall, we have some capacity and flexibility to manage the balance of the exposure going forward. So I think we'll just watch it fairly carefully. There may be some opportune times to take on some more hedging as we move through this process, getting where we've seen the Canadian dollar go, but we'll be flexible. But again, we'll be sticking very much within our defined risk profile, earnings and cash flow at risk that we watch for the company.
Andrew Kuske:

So just following up on that, I mean, implicitly there were some comments made throughout the call, and obviously given your asset base, you're pretty bullish on oil. And so if you're bullish on oil, you should theoretically be bullish on the CAD. Does that come into your thought process on how many hedges you layer in?
John Whelen:

That's all part of the process, yes. I mean, obviously, that's just another indicator at the end of the day that we think about.
Albert Monaco:

I think John's point is right though. I mean, when you're going through these environments and talking about future oil prices, there is a tendency to try and figure out whether you should be doing more or less. I think our philosophy is pretty much to stay at that very high hedged level that he talked about. And to be honest, we are not smart enough to pick the highs and lows, so that we pretty much keep it even.
Operator:

And our last analyst question is from Linda Ezergailis from TD Securities.
Linda Ezergailis:

I have a couple of cleanup questions, maybe more for John. Can you describe some of the cost management initiatives and range of possibilities that you're looking at and what the magnitude of that might be?
John Whelen:

Yes, actually, what I'm going to do, one of the places we have focused a lot quite frankly, we are focusing on cost management across our businesses. One of the places that has been in place for a while is on the Liquids Pipeline side, which is an initiative Guy has had, so I'll let him speak to that little bit in terms of what they've been doing.
Guy Jarvis:

As John alluded to, a lot of the cost management over the last couple of years has come out of Liquids Pipelines. And really, I think, the way I would characterize, what's kind of been driving it is, we've been in the middle of, and continue to be in the middle of a very large capital growth program. At the same time, we've gone through a period here of very large investments in safety and reliability across our system. And I think what was beginning to happen in the organization was a little bit of an approach that said, we're not saying no to anything and we're going to planning for and trying to spend more and more money to do everything. And I think what we've really undertaken in the last couple of years has been extremely helpful in managing our cost is much greater focus on prioritization, timelines, making sure that the initiatives that we've got lined out for ourselves in any particular year, we do well. And the impact that it's had on us is it's made us much more focused, much more efficient, and it's really allowed us to control largely the pace of the growth of cost in conjunction with the growth of the business.
Albert Monaco:

Linda, this maybe a latter point, I think Guy's got it. But another element of cost management is on the capital project execution side. Obviously, in this environment with the downturn, a lot of people are focused on the producer side of the equation, but it's our job to try and search the supply chain for opportunities on the capital efficiency side as well within our projects. And Byron Neiles' team are searching for those opportunities right now as well. So that's on the capital side.
Linda Ezergailis:

Now on the maintenance capital side, can you maybe give us a number of where that came in 2014 and how that might trend in 2015, if you can squeeze out some costs on that front?
John Whelen:

I don't have a specific. It kind of comes back to my comment around distributable cash flow, specifically maintenance capital for a number off the top of my head, Linda. I think when we're looking at it, if you look at combined integrity and maintenance we're seeing that dropped off fairly significantly with the completion of the -- and there is some guidance on that, but it would have come out in prior materials that we have out there, to give you a feel for where the total program is going overtime. And that's largely because the bulk of this integrity effort that Guy was just speaking to has been completed.
Linda Ezergailis:

Maybe I can ask just about another discrete number. Cash taxes, how they might be trending in the next couple of years versus 2014 actuals on your cash flow statement?
John Whelen:

I'm just thinking that one through. Hard one again to project at the end of the day. One place you will see some volatility in taxes is in our segmented breakdown on the mainline, because it is on a flow-through accounting basis. And so you will see those more around a little bit, depending on CCA pools. And so that's probably where it's most visible quite frankly to you. And arguably, we had a particularly low cash tax rate. It was in that segment partly, because of spending that went on, on high depreciation classes during the year. So by a way of some guidance I'd say, that could give you an idea that that number will normalize a little bit over the course of next year.
Linda Ezergailis:

And while we're on the CTS, can you talk about how you see the scale factor settling out this year and over the next couple of years and maybe the residual benchmark toll as well?
John Whelen:

So on the scale factor, we bid at 1.2-ish, and I think that number is probably pretty reasonable. Looking forward with one caveat and that of course is the Line 9 will be coming on, and Line 9 is part currently of our reported basis. And if Line 9 comes on, the effect of course will be to lift the scale factor a little bit, probably closer to 1.3. Linda, we're thinking through quite frankly how we report going forward. But on the current basis that would tend to lift it a bit, because obviously the scale factor is meant to explain things that aren't otherwise explained by throughput x Gretna and the residual toll. And without getting too granular here, I think what we see is that residual benchmark toll lifting over what you've seen from this past year.
Operator:

Our next question is from Chester Dawson from The Wall Street Journal.
Chester Dawson:

I got a question for Guy. He referenced earlier, the Eastern Gulf Coast project, and I haven't heard much of that since it was announced in early 2013. I understand that it was initially exposed to be on target for service this year. Can you update us on where that stands and what problems have risen to delay that, if that's indeed the case?
Guy Jarvis:

I think looking back into our history of examining that market, I think what you're referencing and the time period that you're referencing, the project kind of didn't succeed, because we were unable to secure customer support for it at that time, in the face of other options that customers had available for them to get to new and different markets and on different pipelines. So basically we hadn't been working on it for a while. Now, as we kind of reconsider the landscape and look at the competitiveness and the flexibility of our system to potentially access that market, and look at how the U.S. Gulf Coast is kind of reasserting itself as a very competitive market for Canadian crude, where we've gone back to the drawing board, so to speak. And the reason you really haven't heard too much more about is we're still on the drawing board and we haven't really quite fully gone to market with it yet.
Chester Dawson:

So does that mean you haven't talked to shippers or are you in the process of talking to them now? And how soon might that startup or get in train, if indeed there is interest?
Guy Jarvis:

We talk to our shippers conceptually about a lot of stuff all the time. So I think at this stage, it's still pretty conceptual.
Operator:

Our next question is from Jeff Lewis from The Globe and Mail.
Jeff Lewis:

Just a couple of questions. Can you highlight again what sort of volume risk you potentially see as a result of lower oil prices? I heard the number 200,000 barrels a day. And then I have a second follow-up.
Guy Jarvis:

So I think to get to the 200,000 barrels a day question that is actually linked to a longer-term view of the forecast in an extended period of low price environment. So the 200,000 barrel potential reduction would be out towards, I think we said, 2021 and beyond. In terms of the periods between now and then, we see very little risk, given how fully apportioned we are and the outlook for a timing of new capacity coming into the market. So nothing on the front-end of the curve, potentially that 200,000 barrels a day out on the back-end of the curve.
Albert Monaco:

I mean, as we were saying earlier, we are just full. In fact, we are turning away some barrels to rail. And in this price environment the way we see all the projects carrying on for the oil sands, I think Guy is absolutely right. We just don't see much volume risk in the next few years here on the mainline system.
Jeff Lewis:

And then just secondly, you had some slides on the shrinking oil price differentials. And I'm just curious how that impacts your view on planned rail terminals that you guys were exploring in Illinois and Manitoba?
Guy Jarvis:

Well, I think the one way that we were we looking at in Illinois is really -- and I think to come back to our view on rail, our view on rail is that the way that differentials have gone it does represent the lowest netback price. However, when production is exceeding pipeline capacity, it is required and needs to find its way to market. So when we were looking at rail options in Illinois, it's really in conjunction with our view that through 2018-type timeframe, when our next levels of expansions and Line 3 replacements are in place and potentially KXL ultimately comes into service, there is going to be continuing need to rail those excess volumes out of Alberta. And we were looking for options to have them delivered, to go back into our system downstream, beyond some of our bottlenecks. So we're continuing to look at that. The challenge with that is the unpredictability of how long that window stays open. It is not insignificant investment. And if people view that the window is going to be open for the longer period of time, we think we will succeed. If people think the window is going to be for a shorter period of time, it's not likely to go ahead.
Albert Monaco:

You really do need customer backstopping at these facilities in that. The usage is uncertain, because of the cost of rail versus pipe that we referred to earlier in that chart and other charts. So it really depends on whether or not you can get commitments from your customers. And that's tougher to do in this environment.
Operator:

And I am showing no further questions. I would now like to turn the call back over to Adam McKnight for any closing remarks. End of Q&A Adam McKnight Thanks, John. I would like to thank everyone this morning, and thanks again for your patience. We have nothing further to add at this time. But I'd like to remind you that Leigh and I will be available after the call for any follow-up questions that you might have. Thanks and have a great day.
Operator:

Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.

Enbridge Inc. Q4 2014 Earnings Call Transcript

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Enbridge Inc.
Q4 2014 Earnings Call Transcript