Enbridge Income Fund Holdings Inc. (OTC:EBGUF) Q4 2015 Earnings Conference Call February 19, 2016 9:00 AM ET
Adam McKnight - Director of Investor Relations, Enbridge Inc.
Albert Monaco - President and Chief Executive Officer, Enbridge Inc.
John Whelen - Director, Executive Vice President and Chief Financial Officer, Enbridge Inc.
Guy Jarvis - President, Liquids Pipelines, Enbridge Inc.
Perry Schuldhaus - President
Wanda Opheim - Chief Financial Officer
Leigh Kelln - Vice President, Investor Relations and Enterprise Risk, Enbridge Inc.
Christopher Johnston - Vice President and Controller, Enbridge Inc.
Jeremy Tonet - JPMorgan
Linda Ezergailis - TD Securities
Brian Zarahn - Barclays
Paul Lechem - CIBC
Ted Durbin - Goldman Sachs
Ben Pham - BMO Capital Markets
Andrew Kuske - Credit Suisse
Robert Kwan - RBC Capital Markets
Steven Paget - FirstEnergy
Shaun Polczer - Mergermarkets
Kelly Cryderman - The Globe and Mail
Chester Dawson - The Wall Street Journal
Jeremy van Loon - Bloomberg News
Elsie Ross - Daily Oil Bulletin
Welcome to the Enbridge Incorporated and Enbridge Income Fund Holdings Incorporated 2015 yearend financial results conference call. My name is Ellen, and I will be your operator for today's call. [Operator Instructions] I will now turn the call over to Adam McKnight, Director of Investor Relations. Mr. McKnight, you may begin.
Thank you, Ellen. Good morning, and welcome to Enbridge Inc. and Enbridge Income Fund Holdings Inc. joint 2015 fourth quarter and yearend 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; Perry Schuldhaus, President, Enbridge Income Fund; Wanda Opheim, Senior Vice President and CFO of Enbridge Income Fund; Leigh Kelln, Vice President of Investor Relations and Enterprise Risk; and Chris Johnston, Vice President and Controller.
This call is webcast and I encourage those who listening on the phone 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 the website shortly thereafter. The Q&A format will be the same as prior calls. We'll take questions from the analyst community first, and then invite questions from the media.
I would ask that you wait until the end of the call to queue up for questions and please limit questions to two per person, then re-enter the queue if you have additional queries. And also, the Investor Relations team 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 a summary of the significant factors and risks that could affect Enbridge or could affect future outcomes for Enbridge, which are discussed more fully in our public disclosure filings available on both the SEDAR and EDGAR systems.
I'll now turn the call over to Al Monaco.
Good morning, everybody. I'm going to cover the quarterly and annual financial highlights and our business update, which has a few parts to it today. John's going to then provide color on the results for both Enbridge and the Income Fund. As you'll see, he'll highlight some changes to how we'll look at our funding plan going forward.
I'll warp up on the call with our key priorities in the current commodity price and capital markets environment and our medium-term outlook. And on the outlook, whereas we have historically talked about a combined growth expectation that includes projects in development, we're going to focus that outlook now on the secured growth capital program, and then with upside from development projects above that.
So let's go to the financial highlights on Slide 4. We had a very good quarter, which actually came in stronger than we expected due to higher liquids volumes and excellent progress on cost containment action. So for the year, earnings came in at $1.9 billion or $2.20 a share, 16% year-over-year increase.
2015 ACFFO was $3.15 billion or $3.72 per share, again, a healthy 23% increase. So we're pleased with the results, which show steady and strong earnings and cash flow growth. That stems from the resiliency of our business model, which has been built to weather the environment that we're in today.
So I'll begin the business update now on the next slide with the key elements of what that model looks like. What's concerning our midstream investors today is the sector's exposure to volume declines and excess pipe capacity in drilling-sensitive place. In our case though, our mainline throughput has continued to grow through the downturn, as we had expanded the system.
Now, today we're actually running at full capacity. In fact, we continue to be a portion, so we're turning away barrels from the system. The blue line shows quarterly average throughput rising nicely and in January we had a record of 2.6 million barrels per day x Gretna, so that's across the border.
Volumes can move around of course, but this profile that you see here gives us confidence that we remain pretty much full going forward for the next few years. There's a couple of things that support that view. First, in-flight upstream well sands projects are being completed, which drive the 800,000 barrels per day of heavy ramp up that you see on that second chart.
Unlike the shale plays, the oil sands have long live reserves, where the bulk of capital is putting upfront, so sustaining production is not drilling dependent. The upshot of all of that is that we see x Alberta pipe capacity be constrained for the next few years.
If you look at industry's operating and under construction only case, that's the dash black line that you see on that one chart, it shows a 500,000 barrel per day shortage of capacity through 2020. Guy and his team are looking at incremental expansions that are suited to the current commodity price environment. And what I mean by that is they come with modest capital requirements and can be brought on with manageable permitting requirements.
Now, let's take a quick look at the downstream picture on Slide 6. You can see here the system is directly connected to 1.9 million barrels per day of refining demand, and those refineries are dependent on Canadian crude. More important though is that we've now opened up another 1.6 million barrels per day of markets with our three downstream market access expansions to Eastern Canada, Patoka and importantly the U.S. Gulf.
So we've got a couple of things happening here. The scale and reach of the system attaches Western Canadian producers to markets that get global prices at the lowest possible toll. And then you've got a tremendous refinery toll for feedstock from our system.
Moving to Slide 7. You can see here from the first pie, on this slide, we managed market price exposure to less than 5% on an earnings basis that includes commodity prices, foreign exchange and interest rate risk. The vast majority of our cash flows, about 95%, are underpinned by strong commercial constructs that includes: take-or-pays and CTS, in the case of our mainline; and also take-or-pays on natural gas, in terms of long haul pipes anyway; and then of course cost of service for our gas distribution utility.
So it's this underpinning that provides a very high degree of predictability of earnings and cash flow. A big question on people's minds today, particularly today, is counterparty risk. 95% of our revenues come from investment grade customs. Let me just spend a minute on this one by looking at the credit standing of our Liquids Pipeline business on this next slide.
The left-hand box list top 10 shippers on our mainline, which represents about 80% of the borrowings we move. They either have strong investment grade ratings or they provide equivalent credit enhancement. Same goes for take-or-pay commitments on our regional oil sand systems, once again strong credits here. These companies are the largest and most well-capitalized players in the energy space globally.
What's often forgotten though is that many of our shippers are integrated with downstream refining operations, and we've added that information to this slide here, and some are also single purpose refiner, so obviously they benefit from lower feedstock costs. More broadly, the fact is that the fundamentals of oil in North America means that crude needs to get to market and pipelines are the lowest alternative to get there, which is why we really haven't had any credit defaults to speak of.
On to the next slide now, with regard to execution of our capital program. We had a great quarter with five projects coming in worth about $2 billion. Critical projects were the reversal of Line 9 and southern access expansion, because they opened up important new access for customers, as I referred to earlier.
In fact, Line 9 has now enabled Canadian Eastern refiners to access Canadian barrels, which displaces foreign supply. So for us these projects also draw more volumes through our mainline, which actually help generate the uptick that we saw in December.
We also completed, switching gears here for a minute, the 100,000 barrels per day Heidelberg oil line in the Gulf of Mexico that was three months ahead of schedule actually. The line sits at a depth of 5,300 feet and is a good illustration of the trust that our customers have in our offshore capability.
Let me now provide an update on a couple of secured projects and recent acquisitions. Let's begin with the Sandpiper and Line 3 replacement, which are in the regulatory phase. Now, as you know in January, the Minnesota PUC ruled on how that process is going to unfold. A key outcome of that ruling was that the certificate of need and routing processes for both projects will be rejoined and reviewed concurrently. So we're pleased with that. It allows us to get the planning and construction schedules together for those projects.
In addition, the previous need record for Sandpiper that was part of the original process is also going to be incorporated into their review and that's an important outcome as well. But unlike previous projects in Minnesota, the EIS will need to be completed before the need and routing review for both projects. So this is now a sequential process and that will add some time.
To revise regulatory timeline means that the expected in-service days for both projects will now be early 2019. That's our best estimate today. Importantly, this will also drive a shift in our expected capital investment profile, and that's illustrated in the bottom of the chart that you see. Basically we expect to shift about $2 billion of capital out of 2016 and $3 billion out of 2017. So $5 billion or so of capital will move to 2018 and early 2019.
Now, most of you know that our capital and funding requirements in our five-year plan were pretty much front-end loaded. So this change actually smoothes out the spending profile. And John is going to talk about the funding implications of the Line 3 and Sandpiper change in a few minutes. So that's our expected timeline for Line 3 and Sandpiper.
Let's now move to Slide 11. As you know, we've been developing our Canadian natural gas midstream footprint as part of our priority to extend and diversify our growth, so we're pleased with the acquisition of two operating shallow cut plants in the Montney. The Tupper plants build out our footprint and expand the Montney position, one of the most attractive plays in North America.
Two important attributes of this. First, revenues are underpinned by 20-year take-or-pay commitments. So it fits nicely with the business model. And second, the investment comes with future growth in the region. So we don't look at this as a one-off deal. There is a potential to build out the footprint even more.
Bigger picture, since 2011, with Cabin, Pipestone, Sexsmith and now Tupper, we've established ourselves in what we believe is fundamentally a sound region for the future. And, of course, the broader map here shows how this fits into our overall gas position with alliance in Aux Sable capturing a liquids rich gas very efficiently into the U.S. market and, of course, then on to Don Ontario.
Moving on to Slide 11, power generation and transmission, as we've talked about in the past, the renewables component of this checks all of the strategic boxes for us. So strong fundamentals that drive a very large opportunity set for the future, a good long-term contract that provide solid underpinning that are aimed at minimizing pricing volume risk, and of course we can manage CapEx and operating cost risk on these projects. We now have about 20 in operation today, totaling some 1,900 megawatts. All of this means that we're able to generate a risk-reward profile that's consistent with our liquids and natural gas businesses.
So in November, we announced the 103 megawatt New Creek Wind Project in West Virginia. That's targeted for in-service later this year. And then earlier we acquired a 25% interest in the 400 megawatt Rampion Offshore Wind Project off the southern coast of the U.K. Now, funding for both of these projects and the Tupper plants were included in our secured funding plan that John's going to cover.
We thought we just give you a glimpse of the Rampion Offshore Wind Project on Slide 13. Now, the photo here shows an installation platform. Construction has really just now gotten underway and the first of the foundations was installed, as you can see here. It doesn't really look like much, but when the projects go into service in 2018, there will be 116 3.5-megawatt turbines generating that total capacity of 400 megawatt.
Next slide is project execution of the secured program. This is now on 14. We completed 14 projects in 2015. It was $8 billion of capital, which represented just over 30% of our $26 billion program. So we're ways through that secured program. The table on the right shows the remaining $18 billion of projects in execution.
So a couple of observations here. Projects cover each of our core and new platform businesses. They come with strong commercial underpinnings, and most of them are in the $1 billion or less category.
Now, Fort Hills and Norlite projects, that's about $3.5 billion in total, continue on track and scheduled to be in service in 2017. That's what I was referring to when I talked about the in-flight projects. And the capital for Line 3 and Sandpiper has now been stretched out, as I mentioned earlier.
So now, I'm going to turn it over to John to review our financial results and the funding plans.
Well, thanks, Al, and good morning, everyone. I am picking up on Slide 15, which presents our consolidated earnings performance for the full year and fourth quarter of 2015 relative to 2014. I'm going to start with adjusted earnings and would note by a way of orientation that the segmented reporting format shown on this slide is a little different than what you would have seen in our MD&A.
As you can see in the footnote, we have presented our segmented results, as if the larger dropdown of liquids mainline and regional oil sands pipeline systems to the Enbridge Income Fund last fall had not taken place, and that's in order to provide a clear comparison of the performance of our entire liquids business year-over-year.
For reference or reconciliation of this schedule to our segmented earnings as we report them in the MD&A has been included as a supplementary slide at the end of the presentation. So with that in mind, you can see our businesses taken together delivered very solid results in 2015, notwithstanding challenging industry and financial market conditions.
Earnings from Liquids Pipelines were up $161 million over 2014 for the full year and $103 million quarter-over-quarter, driven primarily by higher volumes in the Canadian mainline. Average deliveries x Gretna were up close to 10% on average for the full year, reflecting growing oil sands production and strong refinery demand, and enabled by expansions of the systems and ongoing efforts to optimize capacity and enhanced scheduling efficiency with shippers.
The liquids mainline finished the year on a high note, delivering a record 2.5 million barrels per day x Gretna in December, which as Al noted, we subsequently outperformed in January, driving a very strong quarter-over-quarter performance as well. The strong performance in the mainline was reinforced by higher earnings generated by a full year of operations from the Seaway Twin and Flanagan South pipelines, both of which went into service in 2014 and benefited from lower upstream apportionment on the mainline in the second half of the year.
This strong year-over-year growth was offset to a degree by a slightly weaker performance from the regional oil sands pipelines and also the fact that interest in the Southern Lights diluent pipeline were transferred to Enbridge Income Fund in the dropdown transaction we completed back in November '14.
And in our November 2015 results, Southern Lights was picked up in the sponsored vehicles and segment, whereas prior to November '14 it would have shown up in Liquids Pipelines, but taken all together, a very strong quarter and a very strong year for Enbridge Liquids Pipelines business.
Moving down to Gas Distribution. Adjusted earnings for the full year increased by $33 million, as EGD benefited under its customized incentive regulation model from a growing asset base, and customer growth that was better than expected and embedded in distribution rates. Year-over-year performance in Gas Distribution was also better, as 2014 included losses incurred under a gas supply contract at Enbridge Gas, New Brunswick, that expired in late 2014 was not renewed.
Despite the strong year-over-year performance, fourth quarter adjusted earnings from Gas Distribution were actually down about $10 million versus the fourth quarter of 2014. This was really due to timing of expense recognition in 2015 versus 2014. Income taxes were higher due to the timing of pension fund contributions, and a relatively higher proportion of EGD's annual operating expenses were incurred in the fourth quarter of 2015 than was the case in 2014.
Gas Pipelines, Processing and Energy Services was the only segment whose contribution declined year-over-year. Adjusted earnings were down $38 million for the full year and about $28 million on a quarter-over-quarter. There are few factors that contributed to this negative variance. Some of them operating factors and some of them as a result of interest segment transfers prior to 2015.
Aux Sable, which has been a drag on earnings all year continue to struggle in the fourth quarter's depressed liquid prices and fractionation margins, substantially eroded processing margins, eliminating any opportunities for upside sharing under it's production contract.
Adjusted earnings for this segment were also impacted negatively by the transfer of the U.S. segment of the Alliance pipeline to Enbridge Income Fund, as part of the dropdown transaction in late 2014 that I mentioned a moment ago. For most of 2014, Alliance U.S. was picked up in the Gas Pipelines segment, for 2015 it's picked up in Sponsored Investments.
But there were some significant positives in this segment. The weak performance from Aux Sable and the absence of earnings from Alliance U.S. were offset by a higher contribution from Canadian midstream assets, as a result of increased take-or-pay fees and higher volumes from the Pipestone gathering system, also increased by slightly higher earnings from the Vector Pipeline driven by lower operating costs and interest expenses.
And an uptick in full year earnings from Energy Services, driven by performance in the first half of the year, as location differentials and tank management opportunities were very favorable. However, the performance of Energy Services did taper off over the last half of the year and particularly in the fourth quarter, due to reduce refinery demand for blended feedstock and increased offshore crude supply.
The weaker fourth quarter performance from Energy Services combined with ongoing poor performance from Aux Sable and the absences of earnings from Alliance U.S. was the major contributor to the reported negative $28 million quarter-over-quarter variance, which you see on this slide.
So down to Sponsored Investments, and even after eliminating the effect of the big 2015 dropdown, full year adjusted earnings from this segment still increased by over $100 million. The stronger performance was driven by a few factors: higher contributions from Enbridge Income Funds, due to the acquisition of Southern Lights and Alliance U.S. in that November 2014 transaction; increased contribution from Enbridge Energy Partners on the strength of higher tolls and growing volume on the U.S. mainline, as well as the acquisition of the balance of Alberta Clipper at the beginning of the year; and higher earnings on Enbridge's share of the mainline expansion and Eastern Access Programs, portions of which came into service during the year.
Corporate segment earnings were up strongly year-over-year, partially due to higher earnings from Noverco and lower taxes, but mostly due to higher net interest margins, as loans to subsidiaries to fund capital projects during the year were higher on average than during 2014. This uplift was partly offset by a full year of dividends on preferred shares issued in 2014 to fund our growth program.
The last loan on the schedule captures the increase in earnings attributed to non-controlling interest that resulted from the dropdown of assets to the fund last September, and it's what you need to reconcile this view of adjusted earnings to the view that we provide in MD&A.
So in summary, a very strong year with positive contributions from virtually all of our assets and right in line with where we expect it to be, which is a testament to our low business risk model that Al referred to earlier, given the industry and market turbulence that we have seen this year.
So moving on to Slide 16 and the cash flow perspective. The strong earnings performance that I just described did translate into very strong year-over-year cash flow growth. Operating cash flow, before changes in working capital, was up significantly compared to 2014, driven largely by the business performance that I just went thorough. ACFFO also increased year-over-year, as maintenance capital in 2015 was lower, driven in part by timing of expenditures as well as cost savings realized due to the completion of some one-time maintenance programs undertaken in 2014.
These positive impacts were offset by the impact of a full year of dividend payments on the preferred shares issued in 2014 to fund the company's growth plans and by higher distributions to non-controlling interest, as payments to third-party investors in EEP and ENF increased year-over-year, both due to the issuance of public units at those vehicles and increases in the distribution paid by those vehicles.
The other line includes any adjustments that we would have made in the determination of adjusted earnings that had an impact on cash flow. A complete explanation of adjustments is included in supporting schedules for ACFFO that we provide in our MD&A and in the news release. So year-over-year, ACFFO was up by more than $600 million, that's a 23% increase over 2014 on a per share basis, again, driven primarily by the growth in our base business and the impact of new projects coming into service.
So slipping forward to Slide 17 on our outlook. For this year 2016, at this stage of the year our outlook remains unchanged from the guidance we provided last December. We're projecting consolidated EBIT in the range of $4.4 billion to $4.8 billion, which is expected to drive out ACFFO per share in the range of $3.80 to $4.50 per share.
And as I noted on the slide, we continue to expect that the biggest driver of EBIT and ACFFO growth in 2016 will be our Liquids Pipeline business with some additional lift from Gas Distribution and Gas Pipelines and Processing.
Moving along to Slide 18, I want to shift perspectives for a momentum and briefly summarize the results of Enbridge Income Fund and Enbridge Income Fund Holdings Inc. or ENF as we call it. But before doing so, it may be helpful to quickly touch on the assets that underpinned the growing cash flow generated by the Fund Group, which is the driver of the dividend growth at ENF.
As you can see on the left-hand side of the slide that after a series of dropdowns from Enbridge over the last few years, the Fund Group now owns and receives cash flow from an exceptional portfolio of energy infrastructure assets, which include our Canadian mainline system, our regional oil sands pipeline network, among others.
ENF and its investors participate directly in the growing cash flow generated by the Fund Group, which it owns jointly with Enbridge. And as would be expected, the year-over-year results for the Fund Group were very strong, driven primarily by the impact of the most recent dropdown transactions completed in September '15 and September '14, but also by the strong performance from the Fund's legacy assets.
The full year results shown on this slide reflect four months of cash flow from the assets dropdown last September and a full year of cash flow from the assets transferred in November 2014. As you can see at the top of the table, full year ACFFO generated by the Fund Group increased by $467 million for the full year and $392 million quarter-over-quarter.
And following down the schedule, you can see that the strong cash growth of the Fund Group enabled it to pay higher distributions to Enbridge and to ENF, which ultimately translate into higher earnings and dividends to ENF shareholders. Earnings at ENF increased by $13 million for the quarter and $44 million for the full year, which supported the healthy dividend increases announced during the year.
ENF raised its dividend in conjunction with both the 2014 and 2015 dropdown transactions. The effect of which is, when you combine them, resulted in year-over-year dividend per share growth of approximately 13% 2015 over 2014. So very solid results for both the quarter and full year at ENF, driven primarily by the dropdown transactions and the ongoing strong performance of the Fund's legacy assets, right in line with what we had expected.
Moving on to Slide 19. This was the outlook we showed last December and there are no changes at this time. We did increase the monthly ENF dividend per share of further 10% to approximately 15.6% per share per month or $1.87 per share on an annualized basis, effective with the dividend payable in February of this year.
We continue to project fund growth ACFFO for 2016 of $1.75 billion to $2.05 billion, driven primarily by the new assets that were placed into service in 2015, which will comfortably support the 10% dividend increase at the ENF level. And our longer-term projections continue to support additional annual dividend per share growth of approximately 10% through 2019.
So moving back now and talking a little bit more about our consolidated funding plan, this is now on Slide 20, that in the current environment we are keenly focused on the execution and funding of Enbridge's secured growth program, while ensuring that we have sufficient balance sheet capacity and flexibility to manage through periods of market turbulence like we're experiencing today, and have the flexibility to pursue good opportunities as they come along.
Slide 20 summarizes Enbridge's consolidated funding requirements over our current planning horizon, which includes 2015 and runs through 2019. The waterfall format will be familiar to many of you from past presentations. But in this case, it focuses on the funding specifically required to support our commercially secured capital program, which on its own, in combination with our base business should generate very attractive per share ACFFO growth, as Al will come back to later.
If you focus on the bar on the left-hand side of the slide, you'll see that our secured capital program for this planning period currently consist of $26 billion of growth capital projects, of which $8 billion were completed and funded in 2015. The remaining $18 billion are the secured investments that Al referred to a little earlier, which will be completed and brought into service between now and the end of 2019, and include the recently acquired interest in wind power facilities in the U.S. and the U.K. as well as the acquisition of the gas midstream assets in Western Canada that Al just described.
Add to that approximately $1.1 billion of projects in later stages of development, which are likely to close over the next little while, plus approximately $8.6 billion of planned maintenance and integrity spending. And subtract from that the funding that was already raised prior to this 2015-2019 planning period for some of these projects. And that left us with at the beginning of 2015 about $30 billion to raise over the planning horizon.
This base requirement is really very manageable if you break it down into its component parts and consider the internal source of funding and the financing that we've already completed to date. Our base business in combination with the current portfolio of commercially secured growth projects is expected to generate $12.4 billion of cash flow net of dividends alone, bringing the five-year net funding requirement down to about $18.4 billion, about $10 billion of new term debt financing and $8.2 billion of equity over the full five-year funding horizon.
On the debt side, if you add refinancing of maturing debt and take into account both cash in hand and about $3.6 billion of term funding that we raised last year, that leaves about $13.7 billion of term debt to be raised across the entire group over the next four years, which we believe is very manageable, given the credit strength of the issuers within the Enbridge Group.
On the equity side, our DRIP and payment in kind programs are functioning very well and are expected to bring in at least $3.6 billion over the next five-year period. The Enbridge DRIP alone raised $700 million in 2015. So this is a pretty conservative estimate for the five-year period.
Add to that about $1.1 billion of equity funding raised at our sponsored vehicles in 2015, and that leaves about $3.5 billion of equity capital to raise across the Enbridge Group over the next four years, less than $1 billion per year on average, which is also very manageable. And particularly given that about $5 billion of our secured capital program expenditures have been deferred, as Al noted, into 2018 and 2019, with the anticipated delays in construction for the Line 3 replacement and Sandpiper projects.
All that said, you can be sure that we're paying close attention to our balance sheet and be proactive in raising capital as needed to ensure we maintain the financial strength and flexibility necessary to execute on our business plans.
And turning now to Slide 21, which depicts the diversity of our funding sources, it's important to reinforce that maintaining diversified access to capital is a key element of our financing strategy. And as you can see on this slide, we do have a variety of vehicles and options through which we can raise debt, hybrid and common equity across the Enbridge Group from both public and private markets.
We're also seeing lots of opportunities to raise new capital at the asset level in the current market. Investor interest is high, particularly among pension funds and we will evaluate these options against other sources of capital available to us.
While we do have a variety of potential options to draw upon, in markets like we're expecting today, we will look to proactively raise capital with the most efficient and cost effective means in light of our needs and objectives. And it's important to emphasize that we continue to maintain in excess of $9 billion of standby liquidity, which should enable us to manage through any market turbulence and raise capital when market windows are open.
So finishing off now, on Slide 22, credit ratings and credit capacity is certainly a focus for many investors in the current market. Our strong and stable ratings are a reflection of our low business risk, minimal commodity and throughput exposure and the stability of earnings and cash flow, all of which was born out in the very solid results that we just announced.
Those credit-friendly factors are further reinforced by a conservative approach to financial risk management, very strong dividend coverage relative to most midstream companies, and the substantial standby liquidity we maintain to support our business and growth plans.
Our credit metrics are elevated at the moment, due to the debt we have incurred to bridge fund the portion of our secured growth program. But they strengthen significantly over our planning horizon, as new projects are completed and commence generating cash flow. We're committed to maintaining strong investment grade credit ratings across the Enbridge Group. And our funding plans and strategies, which we regularly share with the rating agencies are designed with that objective in mind.
And so with that, I'll turn it back to Al to wrap up.
Thanks, John. I will wrap up by outlining our priorities in the current market and our outlook. Despite what is obviously a very difficult environment today, we believe the long-term fundamentals of energy remain strong, and we see very good opportunities to grow our business going forward under the same business model we have today.
But it's also clear that energy and capital markets are under pressure now. As you can see, our business model was build to withstand the ups and downs, and the 2015 results are just one illustration of that. Even so, the management team is very mindful of current market conditions and the need remain vigilant. So here are our four near-term priorities in this environment outlined on the slide.
First, our upstream customers are under pressure right now. The best way we can support them is by focusing on what we do best, providing safe, reliable and growing access to the best markets at the lowest possible toll. Second, we're laser-focused on executing our remaining secured projects, because that's what's going to drive predictable and growing earnings ACFFO and dividends.
Third and equally important, we will maintain and further build out the financial strength and flexibility to support execution of the program and capture opportunities if they arise. That means we'll continue to maintain the strong balance sheet, retain larger liquidity backstop and stick to our conservative approach to dividend coverage.
Also in the past, we've traditionally planned for funding both our secured projects and development pipeline at a single bucket in our five-year planning horizon. Going forward, as John laid out well, our priority is funding the secured capital program. As you saw, our equity funding requirements there are relatively modest and manageable.
Now, that doesn't mean we're going to stop developing new, strategic and value-added opportunities. But for capital investments over and above the secured program, we'll have identified where that funding is coming from, which will be timed to coincide with those incremental investments. Part of that is developing alternative funding sources, as John mentioned, to ensure we have choices and access to effective sources of capital.
Lastly in the priorities, we'll continue to evaluate the opportunities, as I said. So let me reiterate our approach to allocating capital. Slide 24. As we discussed at Enbridge Day, we identified a number of opportunities in each of our businesses. You see them outline [technical difficulty] those will need to pass the stringent investment criteria that we have always employed historically.
As you know, we focus most of our attention on organic growth and asset deals that enhance our strategic position. Given a higher cost of capital today that we are seeing, we'll be lowering the microscope even further to make sure that we're deploying the most optimal projects. And as I said, when we decide to move on opportunities, we'll bring those forward with executable and effective funding sources identified.
Let me conclude with our outlook through 2019. The picture here on Slide 25 captures our expected outlook from our secured program only, so it excludes any upside that stems from our unsecured projects in development. The outlook is in line with what we've previously indicated our business projects generate. Those are the ones in execution over the next five years.
So the $26 billion secured program, which we said has been completed, on its own drive strong ACFFO per share CAGAR growth of 12% to 14% through 2019, pretty solid outcome, even if we do nothing else. As we noted in the past, the profile of that growth will be lumpy, reflecting the expected timing of projects going into service. That level of ACFFO supports what we believe is industry leading average dividend growth of 10% to 12% going forward, again, through 2019.
Importantly, the dividend growth rate does not come at the expense of dividend coverage. We'll continue to be very disciplined there and intend to maintain a conservative payout rate, a ratio rather, which we expect to be at about 2x in this outlook. As I mentioned, we'll continue to assess growth opportunities above the secured program, and those investments would provide added upside to growth beyond the secured program that we're showing here.
So with that, we should open it up to the Q&A session please. Operator?
[Operator Instructions] Our first question is from Jeremy Tonet with JPMorgan.
Just wanted to go back to the guidance, as you were talking about at the end there and just wanted to make sure I was understanding it right. As far as the 10% to 12% dividend growth is kind of reframing the guidance and the 14% to 16% dividend growth that was discussed before, the potential is still there to hit that should you be able to secure more of these unsecured projects at this point. Is that a fair way to think about it?
Think about it, Jeremy. So as I said earlier in the remarks, whereas we used to look at the combined development projects as a single bucket, we've now parsed that out, so you can think of the ACFFO growth that we talked about under the secured program and dividend growth under that program, as kind of the key focus, I guess, you want to call it. But clearly, as I've said, we're not stopping, looking at other opportunities, and those will provide additional upside to that. So that's the right way to look at it.
And then just a follow up. As far as the shifting of the CapEx spend and the impact that would have on your leverage, it seems like the smoothing could have a net-positive impact on your leverage over the planning horizon. I was wondering if you could share any color there.
Jeremy, I think that's right. Deferral of that, given what the challenge we have with such a robust capital program is you're funding a fair amount of capital with debt in anticipation of those projects coming into the service, which they have been over time, so we've been hitting the mark there. But whenever you get a shift like that that actually alleviates some pressure quite frankly on the balance sheet.
The next question is from Linda Ezergailis with TD Securities.
With respect to, just getting back to Jeremy's question about the secured growth outlook, how much of the revised ACFFO per-share growth relates to, first of all, removing the risk component? And then it was mentioned in your press release that the delay in the Sandpiper and Line 3 replacement also contributed to your updated projections. And I'm wondering if, on the margin, were there any other factors related to maybe your outlook for energy services or Aux Sable or anything else around the edges?
Let's start with that one. I don't think so. Obviously, as John mentioned in his remarks, Aux Sable at this point is under pressure simply because of where product prices are. So we have contemplated that in the plan. So I think you can think of the revised numbers, as we said, pretty much the same as we had when we were at Enbridge Day, we just focused more on the secured component there. And on your first question, could you maybe just clarify that question for us Linda?
So there was mentioned I think in the press release that part of your revised outlook came as a result of the delay in Sandpiper and the Line 3 replacement. So I think you've just confirmed that that it's substantially just removing the risk component?
Yes, that's exactly right. That's the way to look at it.
And just a follow-up question, you mentioned that with the higher cost of capital environment, projects are coming more under the microscope. Can you talk about maybe any sort of revisions you have made to your hurdle requirements or exactly how that scrutiny has changed on any sort of opportunity?
It's John, I can speak to that. The criteria and the approach remain the same. Projects have to beat their standalone hurdle rates, their risk adjusted hurdle rates. And those hurdle rates can go up. They also have to demonstrate that they are accretive in the near-term, and obviously, sustainably accretive over the longer-term. So when you factor in current market impacts and so on, all those projects will have to meet to that test. And generally, comfortably, when we bring a project obviously we're comfortable that they are.
So I think that's really how it plays. And at the end of the day, if you start to look at whether it's ACFFO or EPS accretion over time, that clearly takes into account the current market, the market environment. The risk factors that we attached when evaluating the overall project value, those will be adjusted accordingly, if our outlook changes there, if you like the risk of evaluation of any one particular aspect of a project.
And then maybe just to connect that to what we were saying before, Linda, so thanks for raising this again. Another element of this which is going to change is that we're going to be a lot more focused on making sure that when that project comes forward, we have a very clear line of sight to the equity and debt financing related to it to make sure that that's highly transparent and going to happen. And that will be probably something that we haven't focused on in the same way before. As I said earlier, we used to sort of plan the funding in its entirety for both secured and projects and developments. So that's another part of, I guess, the assessment.
The next question is from Brian Zarahn with Barclays.
Not to stay on the topic of guidance, but is the subtle point of you're now breaking out the large portion of free cash flow growth just from the secured projects. But are you assuming now that this is your base growth guidance and really the non-secured projects are becoming less likely versus your last update?
I wouldn't say that they're less likely, but the first part of your conclusion I think is right. We're focusing in on secured as our base. But make no mistake; we're doing exactly the same as we did six months ago in terms of assessing all the opportunities out there. I think the only difference is, as I said in my remarks we're lowering the microscope a little bit lower given the capital markets. And we're going to make sure that we can fund those opportunities as we go forward.
So I think I characterize it as a tightening down on those future opportunities. But the way we're thinking about it as management and where we want to get to is certainly pushing just as we did before to achieve the growth targets that we had in there. But I think for purposes of the base plan, that's where we're guiding to.
And then since you had freed up capital this year and next year with the Line 3 and the Sandpiper delays, how do you view the opportunity to acquire additional assets or would you be more balance sheet-focused over the next year or two in this environment?
I think part of what we were trying to emphasize in the call is that not only we'll be focus on funding the secured program, but developing other sources of capital to ensure that we can capitalize on those opportunities that come up. So that's what we're going to be doing going forward. And by the way just on your comment around opportunities that arise, I think for sure there is going to be quite a few of those obviously in the current environment. We'll emphasize though in a lot of cases, they're cheaper coming to market for a reason, and so we're going to be pretty diligent and focused on making sure that they've got the right business model for us going forward.
The next question is from Paul Lechem with CIBC.
Just on the funding plan, John, you gave us a great update. Thank you. But just wanted to confirm, it doesn't seem there is any change in your timing expectations of raising capital through ENF. So the annual fixed $800 million that you had laid out on the drop-down, is that still the plan to continue to raise that annually, even though there is that shift out at the ENF level of about $2 billion of the CapEx into future years? Are you still looking to raise $600 million to 800 million every year?
Paul, I think if you like, that would be the base plan at the end of the day. But we'll always be, in fact, but particularly in the current market, practical and pragmatic about how and when we get the capital. And we'll try to do it in the most efficient and cost-effective way possible. So you can think, that's the base case, if you will, in terms of how we look at our funding. But it doesn't mean that we won't react to market windows. And as Al says, there maybe opportunities that will stimulate funding that we need to look at. So I think the best way to look at it is that's the base case plan.
And a follow-up, if I can, just on the guidance here. Trying to read the tea leaves on your five-year CAGR number on Slide 25 between the squiggly arrows and the straight arrows you have laid out. On the dividend growth, you've got this 10% to 12% CAGR number through 2019. Given that there's been this deferral of the Line 3 and Sandpiper projects as more back-end loaded, is that -- I mean, the fact that there is a straight arrow there on the dividend side, does that imply that you're looking to try and have dividend growth within that 10% to 12% range every year or could we expect in the short term through 2017 and 2018 that you might be below that range given the growth is more back-end loaded now?
Well, it's a two part answer, Paul. I think part one is that, yes, the arrow implies, I guess, a greater degree of linearity if you want to look at it compared to the ACFFO bars, and that's by design. And driven by the overall confidence that we have in the secured capital program, once again, this outlook is secured only. So I guess we'd have a higher degree of confidence in the linearity, if you want to look it that way. Having said that, obviously, as you know, the dividend decisions are made on an annual basis and if you saw the 2015 results and how we're looking at 2016, I think we feel pretty good about that statement, but obviously, it will depend on what happens year-to-year as well.
The next question is from Ted Durbin with Goldman Sachs.
So on the five-year plan on 2016. You've got $12.4 billion of the FFO. You were $15.4 billion -- I'm sorry, on Slide 20 in your Analyst Day, so you've taken $3 billion off of your FFO net of dividends. If I'm doing this right, you've taken about $11 billion out of your capital. I mean, do you just feel like those are very high-return projects that were in the risk bucket? Is that fair to say that that's all now moving away or am I thinking about that wrong?
Ted, I think yes. They weren't in particularly high return. They were pretty typical projects in terms of what we would have included in the risk bucket. So I may have to step back and think about that one for a minute at the end of the day in terms of what the implied return was there. There is a shifting here as we were speaking to earlier, and really the only two significant effects are the removal of the rest of projects and then the shifting of the capital program to some degree. And those two effects may have had an impact on those numbers.
But I don't think you should draw any huge conclusion about the excess rates of return in that risk bucket. That's not the way we plan. If anything they tend to be underweighted. Typically they're back-ended in the plan and the rate of return is usually not fully kicking in until later. There's usually a stepped-up rate of return or a sloped rate of return. So I don't think that really is a factor playing into these numbers.
I guess to that point, is the Line 3 and the Sandpiper coming in 2019, then is there some tilt to those returns such that we should expect maybe improving returns? And if we extended the plan a year or two, 2020 or 2021, is there any sort of uplift there without capital?
And would apply for Line 3, that's the big one here, of course, there is an upward tilt to that. So you've got an increasing return on equity profile if you want to look at it that way. So yes, that shift applies as well.
And then just small one from me here, but any sense of the type of revenues or margin on the natural gas assets that you bought from Murphy that we can put on our models?
Well, may be we can just generalize it this way, Ted. As we mentioned earlier, we certainly got our microscope down on all new projects coming in. I would say these fit pretty much in the same category as all of our investment if you just look at internal rates of return on equity. You're looking at low double-digit to mid-teen type returns on these projects, so that they fit pretty in much the same category.
And as I said in my remarks, I think returns are one thing, but the risk profile is equally important for us. So having that long-term take-or-pay is important. And so the other part of it too is that it's not just a one-off, as we made note of in the remarks, there are some other opportunities that come with it. But I'd say this one fits pretty much right down in the middle in terms of return expectations relative to the rest of the businesses.
And the next question is from Ben Pham with BMO Capital Markets.
On Sandpiper and Line 3, I was wondering, how do you guys get to the 2019 in-service? I know you characterized it as your best guess at the moment. Maybe you can walk through the construction timeframe for those two projects and then some key milestones on the regulatory filings or the environmental filings?
I'll let Guy correct me here if I'm wrong, but essentially what we're going to do is spend pretty much this year going through the regulatory process. So that's going to be the main focus. We're probably looking at mid-2017 for beginning of construction activities. And obviously, there is a whole bunch of things happening in between as far as procurement, but that's the general schedule. So we're looking at about mid-2017 start.
Not much to add to that. We do have a lot of the approvals in other jurisdictions other than Minnesota related to both projects, which would put us in a position to make a judgment as to whether we begin construction in those jurisdictions in advance of having the full permit in the Minnesota and we will have to make those assessments, as Al said, in 2017.
Yes, that's a good point. I think the way you should look at it is the Minnesota process is the gating item here. Obviously, there is lots of other work to do upstream including regulatory, but we feel pretty good about the rest of it.
And my second question is going back to your guidance, and I know everyone has beaten that to death here in the call. On your base guidance, when you think about flexing your model with Line 3, and you mentioned that it's a total return, your prior plant had those two projects generating cash flows for two years and that through '19 outlook. And I'm just wondering, what's the significant offsets there where you've indicated that there is no change, that secured growth plan versus what you had before?
Well, I think what we're doing, Ben, is we're looking at the -- when we re-ran the numbers, we're obviously removing the impact of the risk projects in development, which is something that we traditionally would put into this look, our funding plan, and we're shifting out the impact of Line 3 Sandpiper, so there is a bit of a ramp up there at the end of the day.
There would have been a few other factors in terms of timing and so on that would have gone into those projections, and also in terms of funding that would have gone into those projections. But at the end of the day, your end period is essentially the same as it was before, and you're substantially getting the cash flow and revenue from those projects and it is ramping up, albeit, over time. So those really are the primary drivers. It's probably little bit of financing effect at the end of the day that impacts the rate of growth over that period.
I think John's hit it on the head there. So in our risk bucket, I guess, if you want to look it at that way, there would have been a financing carry, if you will, in the last portion of the plan, say, two to three years, so you'd have eliminated that, and then as he said, pushed out Line 3.
So a lot of it's the financing drag-down that's removed.
Sorry, so is there another part of that, Ben?
No. Thanks for that.
The next question is from Andrew Kuske with Credit Suisse.
I guess, the question is for Al. You've clearly got really good line of sight on oil sands growth until the end of the decade from a number of projects that are coming online. But I guess maybe let's look beyond your five-year planning horizon. And how do you think about growth beyond that point in the environment we're in, and when do you start getting FID decisions on new incremental projects from some of your customer base?
You're talking about the existing oil sands customer base, is that what you're --
That's a good question. I think in our view, as we said in the remarks, there is a number of projects here in-flight that are going to carry us through the next three to four years. And you've got to also remember there is a constraint to in-pipeline capacity. So as we said we think we're in decent shape there, but I think the reality is the FIDs on new incremental projects are obviously going to be tougher in this environment. Having said that, there are still a couple of fairly sizable opportunities out there that we're assessing right now, that are related to some of those bigger players that have the strength to run through this kind of environment.
If you recall back, when Kearl was originally sanctioned by Exxon and Imperial, that was at the height of the 2008 financial crises, and so you got some situations like that where these companies, because of their size, capability, and long-term view can run through and continue to pursue those projects, particularly, when you've got pretty significant cost reductions happening, both, operationally and in terms of new construction. So I would say, there is still some opportunities out there, but obviously for the bigger inventory of the FIDs that probably has to get pushed out, at least in our estimation.
In terms of how we look at growth beyond 2019, we've been trying to establish opportunities around new platforms, whether its power generation, transmission, natural gas and other opportunities to build that inventory now for the future, so as you very well know you can't just find new opportunities when you need them, you have to start building for the future early, and that's what we've been doing over the last couple of years.
I think we're in good shape. We've probably got more projects on those categories that I mentioned than we can handle to be quite frank at the moment, so I'm pretty comfortable that inventory of future growth and new platforms is building nicely. And then let's not forget Guy in his business has a lot of capital in front of them over the next three four years, but as well he's looking at opportunities to capitalize on the current environment where he can and also build out into the Gulf Coast as he has talked about before.
And then just maybe extending on a couple of your points, if the current balance sheet, let's just call it ballpark-ish $80 billion, and say, 55% of that is really liquids related more than anything else, what kind of proportionality would you ideally want to have on the balance sheet in the future? And if I say liquids, gas related businesses, how do you think about that? Do you think about diversity of business lines?
So it's a good question. You used that balance sheet. We tend to think about this from an earnings or ACFFO perspective. On both of those counts, if you look at the five year plan, I think you're probably right we're going to be 70%, 75% weighted to liquids. As we've said, we would like to seek a better balance better there. But on the other hand, I don't want to put a specific number on it, because that would imply that we need to get there. And although, we would like to be from a strategic perspective a little bit more balanced, the bottomline is always going to come in terms of how we allocate capital and whether or not those opportunities work.
The biggest way to make impact on something like these numbers we've just been talking about is through large scale M&A. And frankly, we haven't seen the value there to this point in most of the opportunities we looked at. Now, it doesn't mean that that won't happen, and our guys are looking at all of those opportunities. But it's hard to put a stake in the ground. We know directionally where we're going to get to, but I hate to put a number on it.
And then, if I may, just one final question, more nitpicky to John. So in the quarter, you had the $19 million of severance costs in the corporate segment. Did you have severance costs in some of the other groups that were, say, regulated assets where you get a bit different treatment?
Yes, we did and they are broken out. If you look through it, you can see them in the MD&A. If you break them out, the total severance costs related to the actions we took last fall was around $45 million pre-tax. And I'm looking at one's at about $38 million after-tax in terms of the cost. And that was spread, Andrew, among different businesses. And for certain businesses, whether it's regulatory constructs, it would have had a different impact.
The next question is from Robert Kwan with RBC Capital Markets.
If I can maybe just ask about the main line and some of the volume trends. Obviously, the overall volume trend's looking good into January. I'm just wondering, especially on light volumes, what you're seeing. And with that, what's the available light capacity? And if we do start to see volume declines, what are you thinking about with respect to converting that to take more heavy to alleviate the apportionment on that side?
So to go to your first question about the trends, we're very pleased with what we saw beginning in December, and it's carrying on into January and February as well, in that our premise has always been that our market access initiatives. We're going to offer the best netbacks to shippers.
And the fact that we've seen such strength on a system, particularly in the way that additional light barrels have come to the system is validating that netback strength. So that's the first view that we have on the trend. The strength in December has continued through January and into February so far, so we're feeling pretty good about that.
Going to the second part of your question about the potential for weakness on light volumes given the oil price environment, it is something that has been in our sites for better than six months now. We have already got one opportunity fully vetted and approved that will allow us to move heavy barrel that's kind of on the lighter end of the heavy spectrum into some of that light capacity.
We're now going through this process of getting approval on a second, which we would hope to have ready to go some time towards the end of the second quarter. So we'll be in a really good shape to try and mitigate any light weakness with moving some of the heavies and at the same time then reducing the heavy apportionment on our system.
Robert, I guess, maybe six months ago we thought that we really need to get our foot on the paddle to try to get some of these opportunities that Guy described, because we thought, well, we're going to -- we definitely see a turn-down of lights. But I guess, we shouldn't have been surprised, but we were a little bit that the light volumes stayed so strong. And when you think about it though, and the fact that Line 9 is now in place, that really has been, I think, a big help to draw lights through the system all the way.
I guess, Al, to that point, you've got the demand toll on the light, which is great. I'm wondering as you're able to move some of these, for lack of a better term, lighter heavies onto the light lines, does that result in an overall net benefit to the system? And if it does, was that already factored into guidance?
Well, let met see if I can answer the first part. I guess, net-net, yes, to the extent that you can reduce your apportionment of heavy and move it on light. So I suppose if lights decline though, then it's only filling in something that was, I guess, could have been projected in light. But as far as the outlook, Guy, can you help out on what we're --
Yes. So I think in terms of the impact of moving some of those heavies over to the lights, as it relates to the mainline outlook, it would be largely indifferent based on what we've had out there. There is potential for some strengthening of the performance for some of our downstream assets when the heavy apportionment numbers are lower. So to the extent the actions we take, reduces heavy apportionment, that does drive some better value out of our downstream contracted pipelines.
And would that be in guidance or not in guidance or would it be upside to guidance?
It would be within kind of the boundaries of the guidance that we've got. I think.
Maybe just the last question, sticking with oil and the charts that you have around investment-grade and who is moving mainline and regional. Just with some of the oil producer downgrades, can you just talk a little bit how that works? Do you need -- is it one rating or do you need two ratings to go non-investment-grade? Can you maybe just talk about the process, if a producer crosses over and the credit enhancement, just how that all works?
Well, the process will differ depending on which system, which contract and so on and so forth. But generally, if somebody is going to cross below an investment-grade threshold, we have right to demand some form of credit enhancement, and typically that will be in the form of an LC backstop. And I think the general observation was, and is, that we have been getting that in the few cases, where we have seen that take place.
So it's not a matter of how many notches really, it's usually the investment-grade threshold that would trigger a requirement for credit enhancement at the end of the day. There is other things we can and occasionally do by way of prepayment of other forms of assurance, but LCs tend to be the typical approach. And as I say, we have been getting those in the few cases, where it's come up.
And is it one rating agency or do you need two rating agencies, like can you be split-rated? And is that still considered investment-grade from --
That depends very much on the system and the contracts.
And just to be clear the Slide 8 is that updated for any recent changes that we have seen?
Not for this mornings changes, no. But otherwise, yes, but not from this mornings changes that came up with Moody's.
I guess, when you've looked at that, how would that change this chart?
We took a quick look. When I look at the changes --
Actually, it does not change that much. There is one. Obviously, we can't identify them, because we can't talk about our shippers. The one just scanning it is -- well, there's one as far as we can see right now, Robert.
Our last analyst question comes from Steven Paget with FirstEnergy.
More strategy question, if I could. If oil sands projects, if they are large, inexpensive -- or if they are large, expensive, and have inflexible production in a more volatile crude oil market, won't capital shift to more flexible oil fields or any one individual well doesn't cost very much? And how is Enbridge positioning itself for this potential shift?
Well, Steven, I think our topline answer to your question is you're probably right. We do know, however, that we hear from a lot of the producers that while their capital is mobile, the nature of the opportunities and the risk spectrum that they evaluate for investing in other countries and other basins comes with a different set of risks versus that which is you could place on the oil sand.
So I think it is difficult to determine where producers will -- how and where the producers will make those decisions going forward, which is why I think when we look at our strategy it falls back to the Al's message about setting up an inventory of opportunities for Enbridge that aren't reliant on the oil sands kind of post 2019.
At this time, we would like to invite members of the media to join the queue for questions. [Operator Instructions] Our first question is from Shaun Polczer with Mergermarkets.
You were talking earlier about midstream assets in the northeast BC. And I'm just wondering if there were specific kind of things that you might be interested in maybe from producers that were looking to monetize some of their midstream, if that was something that you would be interested in pursuing?
The short answer is, yes. And in fact, we have a number of those that we could look at. I will caution though that while we look at a lot of it, seldom do we transact, for the reasons I noted earlier. So what we like about the Montney and other regions in northeast BC is very, very solid fundamentals. And the producers and integrated companies have done a very good job in getting there cost down.
So we like the basin fundamentally, where we can bring something to the table to perhaps acquire or build midstream assets for gas, where we have some capability, we would look to do that, but the proviso is that it's got to fit the business model. And so I guess, what I'm saying, we look at a lot, but getting to the ones we like takes more time.
And follow-up, last year there was a lot of talk about the dropdown on the U.S. assets, and you delayed because of the market conditions and all that. I was just wondering, if there was any circumstance, where you might bring that back on to the table? And if so what would it be?
I think at this point in time, we're pretty much where we were back then, in that the current market conditions for MLPs. The entire sector has been very difficult. So obviously raising capital at that level is very problematic. So we've got to make those transactions work for ourselves driving down the asset, but also the unit holders of EEP in this case.
So I would say we're pretty much in the same position. The circumstances that could change that obviously are strengthening early, stabilizing from here the MLP sector, and particularly, EEP. It's not to say that we wouldn't look at other opportunities to dropdown specific assets, but generally speaking that's going to be very difficult in the next little while.
The next question is from Kelly Cryderman with The Globe and Mail.
Just going off the comment about weaker performance from regional oil sands pipelines, can you describe in more detail why that's happening?
Kelly, that was really due to contract falling off one of the pipeline systems at the end of the day, and I'm looking at Guy here, actually get some incremental volume, uncommitted volume coming on the system, it wasn't quite enough to offset the impact of that one particular contract.
Yes. I have nothing to add to John's comment.
And can you tell us about, which contract that was?
No, that's a commercially sensitive.
Also, you had to reduce your workforce by 5% in November. Do you have plans or is there any provision for future layoff this year?
So I think it's not surprising that people focus on layoffs, but our approach to efficiency more is multi-facetted. So it starts with trying to optimize our capital, making sure that we're doing all we can to extract value from the supply chain, which we've had very good success on. And then an element of it obviously is workforce. And as we pair down the number of projects going forward, obviously, there will be some effects from that, around about late last year, but obviously we'll continue to monitor that and we're always trying to assess that. So we don't have any specific plans on that today, but we're obviously looking at it very closely going forward.
The next question is from Chester Dawson with The Wall Street Journal.
Just two quick questions. First, in terms of the Northern Gateway project, do you expect to be able to begin the construction prior to the exploration of that, which I believe is the end of this year, even if you don't have agreements with all of the First Nations that you're hoping to reach accords with? And secondly, can you talk about how the Alberta Clipper project, maybe what the status is in terms of the application and whether that will be impacted -- the timeline will be impacted by the Line 3 delay?
Let me start with the Gateway question. I think the short answer is our ability to begin construction before the end of the year is really quite remote at this point. There is a number of things that we still need to do from a regulatory perspective. And one of those would be to likely seek an extension of that deadline that you were talking about.
The things that need to be done obviously are clearing the regulatory conditions, so that's one of the things. Obviously, firming up shipper commitments is another. I would say though, all that aside, the bigger issue is making sure that we're continuing to work with our communities. We're doing that quietly making sure that we're continuing to build trust with them, responding to the issues and questions they have with the project.
So I think we're probably in a phase where we need to get more comfort around support for the project from a community and First Nation's perspective. I will say that despite this being a little bit below the radar, as of late, we're making very good progress with both communities and First Nations along the right of way. And, if anything we've seen some pretty good interaction, I'll call it, over the last little while. So that's really the main focus right now.
As we've said before, Chester, we're not looking at our watch here on the project. This really will take some more time to develop and that's what we're focused on. Now, if you look at the environment we're in versus vis-à-vis the production profile. There is obviously not as much of a panic, if you will, with respect to volumes in that. I think the mainline that we have can handle a good chunk it for a while here. So that's the process we're in.
With respect to Alberta Clipper, I think what I can tell you is that the supplemental environmental impact statement is, which is being assisted in preparation by environmental contractor is well in hand, and I believe that's being forwarded to the Department of State for review. There is, as you know, a process that occurs after that to get agencies to comment on, all of which would tell us that if everything goes well, we should be able to see that going forward for endorsement near the end of this year.
I think there was another element of your question. I think it was Line 3 delay. We don't think that that will impact the Alberta Clipper process itself. As you know, we're running the majority of volumes through the Alberta Clipper Line right now through managing interconnections through our existing system. So I don't see any real impacts between the two given, where Line 3 timing is at the moment.
Just to clarify, the extension that you spoke of for the Northern Gateway, when would you expect to apply for that?
We don't know yet, is the short answer, Chester. We're just assessing right now what we would need to do for that. And we're really in evaluation mode there.
And the next question is from Jeremy van Loon with Bloomberg News.
Jeremy van Loon
Just a quick question on investment and future investment. As you look beyond your next wave of investments, how do you see Alberta and maybe Canada more generally as investment destination compared to some of the other options that you have out there?
Well, obviously, it's very difficult environment right now. But perhaps one of the more optimistic ones, when you are in the depths of this kind of environment, it's very easy to be focused on the near-term. I will say that what's very impressive is the degree of success that's our producers and other integrated companies have had in brining down costs. And I think once we get through this very difficult time, Jeremy, I think we will see that the industry come out very, very strong just because of the major impact on cost structure.
So my view is that overtime, whereas the oil sands and other investments in Alberta are viewed at least at the margin in terms of full cycle costs, I think you're probably going to see an ability for the oil sands to make progress on that and get more to the medium part of the curve, if you will, in terms of cost just because of the great work that's being done by producers and integrated companies right now.
Jeremy van Loon
And maybe just a follow-up to that. I mean, as you look to other sectors, certainly transmission or renewable or electricity generation, how does Canada in general compare to some of the other jurisdictions you're looking at?
Well, as far as wind resource and solar resource, very good on the renewables front, stacks up quite well, we have some number of projects in Canada. And obviously, in Alberta, in particular, given the new Climate Leadership Plan, we think this is a very good environment to invest in renewables. You've got a great resource plus you've got a set of conditions from a policy point of view that would support further investment here. And obviously, we're an Alberta-based company, so this is good news.
I would say though that certainly in United States, where you have a lot of regions there and as well in Europe, who have perhaps more prescribed targets on renewable generation, those are also very attractive as well. So this is one of those pick and choose type of decisions we always make as to where to put the capital. So that's how we look at it right now.
And the next question is from Elsie Ross with Daily Oil Bulletin.
You talked about the shifting some of your light or heavy barrels on to lighter shipment. How much of a difference would that make in terms of volumes? And what's the process?
So the process that we go through really has three elements to it. The first element of it is, is that we need to make sure if we move a heavier barrel on to our light system that we're somehow not devaluing the light barrels that we are shipping. So crude quality and management of the crude quality is the first thing we look at.
The second thing then we look at is, is what impact does this have to our operations and integrity management plan. We don't want to be creating a situation where we're moving a heavier product onto one of our light lines and then have been creating a negative impact on the pipeline integrity at all. So that is a huge part of the exercise.
And then, obviously, the third component of it is if you're looking to have a bit of different crude blend put into your system, you've got to make sure that it's valuable at the refinery level. So the first two elements of that we manage ourselves. The third element of it obviously we need to engage our refinery customers. In terms of the magnitude of what this could mean, we are targeting to try and have as much as 100,000 barrels a day of that opportunity by the end of the second quarter of this year.
Now, have you actually shifted that first one? You said there is two groups. Have you shifted the first one over already?
No. So we do have one of them approved. And given the strength of the light volumes to this stage in time, we have not had to use that.
And ladies and gentlemen, we have reached the end of our question-and-answer session. If we did not get to your question, please follow-up with the Medial Relations team. And I would now like to turn the call back to Adam McKnight for any closing remark.
End of Q&A
Thank you. We have nothing further to add at this time. But I'd remind you that the Investor Relations teams will be available after the call for any follow-up questions that you may have. Thank you very much for joining us this morning. And have a great day.
Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.
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