Enbridge Energy Partners' (EEP) CEO Mark Maki on Q4 2015 Results - Earnings Call Transcript

| About: Enbridge Energy (EEP)

Enbridge Energy Partners, L.P. (NYSE:EEP)

Q4 2015 Earnings Conference Call

February 17, 2016 10:00 am ET

Executives

Sanjay Lad - Director, IR

Mark A. Maki - President and Principal Executive Officer

Stephen J. Neyland - VP, Finance

Guy Jarvis - EVP, Liquids Pipelines

Jonathan N. Rose - Treasurer

Analysts

Brian Zarahn - Barclays

John Edwards - Credit Suisse

Theodore J. Durbin - Goldman Sachs

Robert Balsamo - UBS

Andy - JP Morgan

Sunil Sibal - Seaport Global

Sharon Lui - Wells Fargo

Operator

Good day, ladies and gentlemen, and welcome to the Enbridge Energy Partners Fourth Quarter 2015 Earnings and 2016 Guidance Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, today's call is being recorded.

I would now like to turn the conference over to Sanjay Lad, Director of Investor Relations. Sir, you may begin.

Sanjay Lad

Thank you, Sharon. Good morning and welcome to the 2015 fourth quarter earnings and 2016 guidance conference call for Enbridge Energy Partners. This call is being Webcast and a copy of the presentation slides, supplemental slides, condensed unaudited financial statements and news release associated with it can be downloaded from the Investor section of our Web-site at enbridgepartners.com. A replay will be available later today and a transcript will be posted to our Web-site shortly thereafter.

As a reminder, the Partnership's results are also relevant to Enbridge Energy Management or EEQ. I will be available after the call for any follow-up questions you may have. Our speakers today are Mr. Mark Maki, President, and Mr. Steve Neyland, Vice President, Finance. Available for the Q&A session, we also have Mr. Guy Jarvis, Executive Vice President, Liquids Pipelines; Mr. Jonathan Rose, Treasurer; and Ms. Noor Kaissi, Controller.

Moving to our legal notice, this presentation will include forward-looking statements. Any statements made or discussed today that do not constitute or are not historical facts, particularly comments regarding the Company's future plans and expected performance, are forward-looking statements. Actual results or outcomes may differ materially from those that may be expressed or implied. The risks associated with forward-looking statements have been outlined in the press release and the Partnership's 2014 annual report on Form 10-K, subsequently filed quarterly report on Form 10-Q and current report on Form 8-K.

This presentation also includes certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found in the Investor section of our Web-site. Please proceed to Slide 2.

I will now turn the conference call over to Mr. Mark Maki, President.

Mark A. Maki

Thank you, Sanjay. Good morning and welcome. On the call today, we will highlight how the Partnership's defensive business model is well-positioned in the current environment. We'll then discuss crude oil fundamentals and the Partnership's strategic position. Steve will then take the call from there and address the fourth quarter financial highlights and then present our 2016 financial guidance. With that, please turn to Slide 3.

We're very pleased with the Partnership's solid financial and operational performance in 2015, and this is largely attributable to the execution of our market access programs and the meaningful cash flow contributions from our strong organic growth program.

Additionally, we achieved record total deliveries approximating 2.9 million barrels per day in 2015 on our liquids pipeline systems. As we will discuss in the following section, we expect continued strong deliveries on our Lakehead, North Dakota liquids pipeline systems throughout 2016.

The Partnership achieved the top end of its full year 2015 adjusted EBITDA and cash flow available for distribution guidance ranges. Strong operational performance in our core liquids pipelines business is the key reason. Finally, we strengthened the Partnership's liquidity by securing approximately $1.9 billion of funding in 2015, which positions the Partnership with no expected equity requirements in 2016.

Our confidence in the long-term outlook is supported by the Partnership's very strong and unmatched strategic position. Given our liquids pipeline system's premier connectivity in North American refining centers, our competitive transportation rates and our enhanced market access program, we expect demand for our pipeline systems to remain strong.

Our ability to deliver strong and predictable earnings and cash flow in the current environment is a reflection of the resilience of our low-risk business model. Our business model performs well and in a predictable fashion in high or low commodity price markets.

Please turn to Slide 4 and we'll highlight the Partnership's strengths and our defensive business model. I want to take a moment to reinforce again the low-risk and stable nature of our business model as presented in the chart. Turning to the pie chart in the upper right quadrant of the slide, less than 5% of Partnership's 2016 cash flows are subject to direct commodity price exposure.

In 2016, our core liquids pipeline business is expected to provide greater than 90% of the Partnership's earnings and cash flow available for distribution, which is predominantly underpinned by long-term low-risk contract structures such as cost of service and indexed toll. The result is a stable and defensive utility like contract risk profile.

We are often asked how the current low commodity price environment affects our business. We do not anticipate the current environment of low crude oil prices to materially affect the underlying earnings and cash flows from our liquids pipelines business. Certainly the low price environment is hurting oil and gas producers.

Partnership's customer base is comprised of very strong high-quality companies. More than 90% of the Partnership's credit exposure is to investment-grade counterparties. The remaining non-investment-grade customers are closely monitored and appropriate measures are taken to mitigate the credit risk.

Please turn to Slide 5. In the current low commodity price environment, we remain very focused on providing our customers a safe, low-cost and reliable transportation to key markets to ensure they receive the best netbacks. The Partnership's Mainline pipeline system is running at capacity with a number of lines being oversubscribed.

As illustrated in the chart in the upper right quadrant of the slide, the deliveries in our Lakehead system have increased sequentially and we expect demand for our pipeline systems to remain strong with new market access projects entering service.

Moving to oil sands growth outlook chart, the Canadian Association of Petroleum Producers or CAPP continues to forecast increase in crude oil supply. Supply growth from Western Canada is expected to increase about 800,000 barrels per day as recently completed oil sands projects ramp up and those currently under construction enter service to the end of the current decade. Oil sands projects typically have a long-lived and steady production profile and are not expected to curtail production as this could potentially impact the lifecycle returns from the projects.

Demand for pipeline takeaway out of Western Canada is anticipated to remain strong as the region currently has inadequate pipeline capacity. Region is forecasted to be short greater than 500,000 barrels per day pipeline capacity by 2021.

The reliable market access and transportation rates provided by the Enbridge system together with the strong supply growth and pipeline takeaway constraints from Western Canada gives us confidence that we will be able to see high utilization of the Partnership's liquids pipeline systems.

Please turn to Slide 6. Now history can be a great teacher. In this instance, we think it's very important to highlight how the Western Canadian Sedimentary Basin has behaved over time in a variety of crude oil price environments. This chart stretches back to 1990 and captures a number of painful down cycles in crude oil price. And history confirms a few things for us.

First, once running, oil sands production does not shut in. Second, projects under construction get completed and we see that with steady growth in supply over time. Third, as long run price expectations are clear, investment in new oil sands will continue provided there is access to market. And finally, Enbridge has and always has been connected to some of the most attractive markets in North America for Canadian oil. In the future, as in the present and often in the past, Western Canada is short pipeline takeaway capacity. As such, our systems and the services we provide are critical to satisfying the energy needs of North America.

Please turn to Slide 7. Volumes of the Partnership's liquids pipeline systems continue to increase as additional market access projects enter service. Our pipeline system is uniquely positioned to offer shippers from Western Canada and the Bakken unparalleled optionality to access markets in Eastern Canada, the U.S. Midwest PADD II region and the U.S. Gulf Coast refining centers, with direct or indirect access through third-party pipelines to over 8.5 million barrels per day of refining capacity. The demand pull through our pipeline system is tremendous.

The enhanced market access created by Enbridge's U.S. Gulf Coast extension, the Line 9B reversal and expansion project to Montreal and the Southern Access Extension to serve markets at Patoka will all serve to further facilitate long-term downstream hold on our system, especially for light crude oil. With multiple high-quality markets connected to our system, shippers have enhanced flexibility to reroute their monthly volume nominations to alternate delivery points should a market disruption occur, like a refinery outage.

Again, it is important to note that long-term take-or-pay contract structures underpin both Enbridge's supply basin takeaway pipeline systems and the downstream system such as Line 9B, the Southern Access Extension, Flanagan South and Seaway. So shippers are highly incentivized to utilize this capacity which serves to pull volumes to the Partnership system which is sitting right in the middle.

Please turn to Slide 8. I'll turn the call over to Steve to elaborate on the Partnership's low-risk business profile before reviewing our fourth quarter results and presenting our 2016 outlook.

Stephen J. Neyland

Thanks Mark. The next three slides demonstrate our low-risk business model and related long-term contracts. More than half of our cash flows, as depicted with the green wedge of the chart, are underpinned by long-term cost of service arrangements which mitigate the sensitivity of volume and commodity prices on our business' distributable cash flow.

The blue wedge representing our fee-based component of our cash flows is predominantly generated by the indexed toll component of our Lakehead system. These indexed volumes are benefited by the fact that primary basins we serve are short on pipeline capacity. In addition, our rates for transportation are much more competitive than rail and less expensive or comparable to competing pipelines. We also offer much greater market flexibility than our competitors.

These are some of the major factors of why we expect continued high utilization rates on our Lakehead and North Dakota systems, which source their volumes from the Western Canada and Bakken areas respectively. Additionally, to the extent there are volume reductions, we would see more expensive rail option to be first impacted on our systems to remain heavily utilized.

In summary, our core liquids pipeline business generates greater than 90% of the Partnership's distributable cash flow and the result is a stable and defensive utility like contract cash flow profile.

Please turn to Slide 9. There's little question that certain producers have been adversely affected by the low commodity price environment. In this commodity price cycle, it is important to highlight the quality of the Partnership's customer base. Approximately 90% of our shippers are investment-grade credit. The remaining non-investment-grade customers are closely monitored and appropriate measures are taken to mitigate this credit risk.

It is also noteworthy that the mainline shippers nominate volumes on a month-to-month basis and our pipeline systems provide a high level of reliability and connectivity to premium markets. Our risk management program, the Partnership continues to actively manage and mitigate counterparty credit risk.

Please turn to Slide 10. The defensiveness and sustainability of our cash flows is further highlighted by the remaining term on our key contracts. First, a vast majority of the Partnership's system expansions over the past decade have been undertaken on a cost of service basis. As you can see, the remaining life of these contracts averages greater than 25 years.

Next, the fee-based component of our cash flow profile is underpinned by an indexed toll structure. While fee-for-service structure may suggest the revenues would fluctuate based on actual system utilization, it is critical to reiterate that these indexed volumes are benefited by the fact that the primary basins we serve are short pipeline capacity that we've discussed.

Our Lakehead system generates approximately 80% of the Partnership's indexed toll revenues, and collectively Lakehead and the Enbridge liquids pipeline systems transport more than half of the crude imported by the United States from Western Canada. Our extensive and recently expanded pipeline system enhances our market access. This access along with competitive transportation rates from the regions we service provides us with a high level of confidence and continued high utilization of the Partnership's liquids pipeline systems.

Please turn to Slide 11. In 2015, we made solid progress in our liquids pipeline market access programs. Three cost of service projects within EEP are outlined on the slide. We also highlight Enbridge's new market access projects that entered service during the fourth quarter, specifically the reversal and expansion of Line 9B to Eastern Canada market and the Southern Access Extension into the Patoka market, each under ship or pay contract structures. These recently completed projects will enhance the demand pull on our EEP Lakehead pipeline system.

Please turn to Slide 12. I also would like to provide an update on our Sandpiper project. Earlier this year, we received written orders from the Minnesota Public Utility Commission for the Minnesota portion of the proposed Sandpiper pipeline project and the Line 3 pipeline replacement project. We believe that the directions from the Minnesota PUC and most of the decisions set out in the orders were consistent with expectations and provide clarity on process matters.

However, the orders require that a final environmental impact statement for these pipelines be completed prior to the commencement of the certificate of need and route-permit processes. We continue to review the impact of the orders on the project's schedule and cost estimates. Based on the orders and our preliminary assessment, if upheld, the process set out in the orders is likely to delay the planned startup of construction, which would cause a shift in the in-service dates to early 2019 for the Line 3 replacement and Sandpiper projects.

The need for these projects is very clear. Sandpiper is an important project for Bakken shippers and will add much-needed capacity out of the region, enabling lower cost access to markets in the U.S., Mid-Continent and Eastern Canada. The Line 3 replacement is critical to industry because it ensures our shippers of enhanced reliability and assurance of moving anticipated end-of-decade throughput levels on our system of 2.85 million barrels per day. We continue to work cooperatively with the permitting authorities, state agencies, elected officials and the public to bring these projects into service.

Let's move forward to Slide 13. In 2015, Enbridge communicated its objective to propose selective drop-downs to EEP. While the highly attractive U.S. liquids pipeline drop-down backlog has been identified, market conditions need to strengthen and be supportive to execute upon this strategy.

Please proceed to Slide 14 where we would view the Partnership's financial results. For the fourth quarter, the Partnership reported adjusted EBITDA of $450.7 million and distributable cash flow of $214.5 million. Distributable cash flow for the fourth quarter was $34.3 million lower when compared to the third quarter, primarily due to higher cash interest attributable to the $1.6 billion public debt market offering closed during the quarter. We are pleased with the record deliveries on our liquids pipeline systems which averaged 2.88 million barrels per day in 2015, an increase of approximately 10% over 2014.

Full-year 2015 adjusted EBITDA and distributable cash flow were $1.77 billion and $949 million respectively. The Partnership's full-year 2015 distributable cash flow increased 17% over 2014 and adjusted EBITDA for the same period increased 14%. Our full-year as-declared distribution coverage ratio on a cash basis was 1.11x, and was 0.92x assuming the inclusion of the paid-in-kind distribution.

Our debt-to-EBITDA leverage metric at the end of the fourth quarter was 4.6x, which considers 50% equity treatment for the hybrid financing instruments we currently have in place. The leverage metric compliant within our credit facility attributes 100% equity treatment for the hybrid instruments. Hence, we are comfortable in compliance with those leverage metric requirements. The main items eliminated from these adjusted results include unrealized non-cash mark-to-market net gains and losses and other items noted in our supplemental slides.

Please turn to Slide 15. For 2016, we expect the Partnership's adjusted EBITDA to be between $1.8 billion and $1.9 billion. Distributable cash flow is expected to be between $860 million and $920 million. Distribution coverage is expected to be between 0.8x and 0.9x with cash coverage to range between 0.95x and 1.05x. For the Partnership, greater than 90% of our forecasted 2016 adjusted EBITDA and distributable cash flow will come from our core liquids pipeline business, with the remainder from our natural gas business.

Moving down to the 2016 volume outlook for major asset systems, we expect demand for our pipeline systems to remain strong and expect total liquids pipeline system volumes to increase approximately 13% over 2015 based on the cumulative midpoint of the guidance ranges. Enbridge's recent new market access projects which entered service during the fourth quarter increased the Partnership's fourth quarter utilization and is expected to continue into 2016.

Deliveries on Lakehead are anticipated to meaningfully increase at an average between 2.6 million to 2.8 million barrels per day. As it relates to our North Dakota system, we forecast average delivery to be between 320,000 and 350,000 barrels per day. We expect strong pipeline system utilization to continue with the expanded market access for Bakken light oil. Deliveries on our Mid-Continent system are forecast to remain steady between 200,000 and 220,000 barrels per day.

Moving forward to our natural gas business, we expect a decline in overall system volumes through 2016 as our system outlook is affected by reduced drilling from producers in and around our assets. We expect natural gas throughput to be between 1,600,000 and 1,785,000 MMBtu per day and NGL production to be between 70,000 and 75,000 barrels per day. Sustainable cost reduction measures undertaken in 2015 are expected to support the gas segment's cash flow outlook. Our supplemental slide deck provides additional detail to support our 2016 outlook.

Please turn to Slide 16. This slide illustrates the Partnership's distributable cash flow trend from 2015 to our 2016 forecast. Growth in distributable cash flow is expected to be generated by full-year contributions of the Mainline expansion growth projects, which began service in 2015.

Next, higher forecasted total liquids pipeline system deliveries are expected to average between 3.12 million and 3.37 million barrels per day. This is also a positive contributor to expected cash flow growth. Finally, the Partnership expects to exercise its option to acquire an additional 15% interest in the Eastern Access series of Lakehead system expansions at book value in mid-2016. This growth in distributable cash flow is more than offset by a few items, most notably from higher cash interest associated with a $1.6 billion debt placement in the fourth quarter of 2015.

Financial performance in our natural gas business is expected to be lower in 2016 due to reduced drilling. While the outlook for our North Dakota trunkline remains strong, lower forecasted demand for gathering and rail loading capacity out of the Bakken is expected to be a headwind for these particular North Dakota assets.

The Partnership expects higher property taxes and other costs in 2016 attributable to new assets placed in service. However, these increases are offset by cost reduction actions within the Partnership. Collectively, the culmination of these items is expected to result in 2016 distributable cash flow of between $860 million to $920 million.

Let's move forward to Slide 17. The Partnership remains focused on prudently managing its balance sheet and maintaining its investment grade rating. We expect our growth capital expenditures to be significantly lower in 2016 than in recent years, largely due to slower spending on our major projects, notably Line 3 replacement and Sandpiper pipeline projects. A shift in these project in-service dates is expected to result in lower capital spending on the projects in 2016.

Our 2016 capital expenditures are forecasted to be approximately 20% lower than prior year at $900 million. Our financial flexibility is further enhanced by the timing in which the Partnership may exercise its book value call options to increase its economic interest in the Eastern Access series of expansion projects from Enbridge. The book value call option is approximately $360 million.

Finally, the Line 3 replacement participation in joint funding level with Enbridge is under consideration by an independent committee of the Board of Directors and has not yet been determined. We reflected a credit of $350 million to reflect one possible scenario to represent the approximate dollars that would be remitted to EEP by Enbridge at the capital contribution of Enbridge for an economic interest in the jointly funded project.

Our capital investment expenditures are forecasted to be approximately $900 million and we had approximately $1.2 billion of available liquidity at the end of the fourth quarter. Importantly, the Partnership does not expect to access the equity market in 2016.

Please turn to Slide 18. I'll now turn the call back over to Mark for his closing remarks.

Mark A. Maki

Thank you, Steve. Today we focused our comments quite directly on three concerns we hear from our investors in the current environment, utilization of our liquids pipeline systems, quality of the customer base and the nature of our revenue arrangements.

Our liquids pipeline system's premier connectivity to North American refining centers, our competitive transportation rates, our enhanced market access program and not enough pipeline capacity out of Western Canada translates into expected demand for our pipeline systems remaining strong.

System utilization in December is running at record levels and we expect this positive trend to continue into 2016. Our ability to deliver predictable earnings and cash flow in the current environment is a reflection of the resilience of our low-risk business model which is built to withstand the type of downturn the industry is currently facing. The Partnership's funding requirements are manageable and we do not expect to access the equity market in 2016. The long-term outlook for the Partnership remains strong and we appreciate your investment in Enbridge Energy Partners.

With that, I'll open the lines for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Zarahn with Barclays. You may begin.

Brian Zarahn

On your outlook for 2016 oil pipeline volumes, what are some of the key assumptions on the low-end and high-end of the range for the Lakehead system?

Mark A. Maki

Maybe Guy Jarvis, you want to field that one?

Guy Jarvis

Sure. Brian, I think the issue that we're watching most closely in 2016 is what's going to be happening with the conventional light volumes, primarily out of Canada. We've been a little bit concerned about some weakness on that side of things coming into the end of 2015, but the strength of – we always said Line 9 and Southern Access Extension would provide us with the strongest netbacks. So we've been encouraged by the amount of new light volume that's come to our system to serve those markets. But we're still watching that very closely. So the weakness side could be on the lights.

We have an ability to mitigate a pretty substantial amount of light erosion with the flexibility to move different commodities on different lines. So we've already got one option where we can immediately move to alleviate some of that light volume weakness and we're working on a second that we hope will be complete by the end of the second quarter. So the weakness is on the light side but we're doing a lot to get ready to mitigate that in advance.

Brian Zarahn

In terms of preparing for some downside in the light volumes, do you feel comfortable you can replace that with heavy or are you assuming on your guidance range some price assumption that would provide a floor for volumes?

Guy Jarvis

I think it's more around the range of mitigations. We are currently, a portion I think in February, 14% on the heavy side. So there's more than a couple of hundred thousand barrels a day of heavy that's still looking to move in our system. So our focus is trying to identify a heavy crude that can flow in with some of our lights. We've already got one of them approved that we can do and we're working on a second.

Brian Zarahn

Thank you, Guy. And then looking at expansion CapEx, is there potential for 2016 to come in below 900 million, whether it's on Line 3 or some of your other growth projects?

Mark A. Maki

It's Mark. There's obviously in any kind of capital expenditure forecast a fair bit of variability in some of the numbers, I mean that is a range. And typically if you look at us over history, we tend to probably overestimate our CapEx spend in any particular year and it tends to come in low. So we showed it as a plus/minus on the slides for a reason, that is a little bit of – and certainly we're going to be looking to control CapEx besides. So to the extent we've got discretionary spend, we're going to delay or defer as we need to.

Brian Zarahn

And along those lines, you mentioned on the financing you're not going to access the equity markets this year. You do have EEQ. Can you elaborate a bit more on your financing plans for 2016?

Mark A. Maki

Sure. Jonathan Rose, you want to field that?

Jonathan N. Rose

As we highlighted through the slides, we have sufficient liquidity to manage our CapEx going forward on a 12-month basis, and as you've highlighted, we do have the payment in kind feature on the EEQ shares that does provide us with a base level of equity. So through that perspective, we don't see at this point that there's a need for any other incremental external equity.

Brian Zarahn

Okay. And then on another – my follow-up question is also CapEx related. Given the permitting delays, how should we frame the cost estimates and potential changes for Sandpiper and Line 3?

Mark A. Maki

Basically, Brian, I think we're going to be a little reluctant to peg a number to it just yet today, and the reason for that is we've got a little bit of process we need to work through yet. And then when the time comes, we'll look at our construction alternatives and what the situations are with the customers in terms of timing and so forth. So it's a little hard to really pin down a number. We do, we would expect, it was alluded to, that it would be a little bit higher, but we're not going to put a range on that today.

Brian Zarahn

I will stay tuned. Thank you, Mark.

Operator

Our next question is from John Edwards with Credit Suisse. You may begin.

John Edwards

Can you remind us on the Eastern Access call option exercise, what kind of flexibility do you have on that, I mean maybe could you defer and particularly given where the emphasis on balance sheet these days for most folks?

Stephen J. Neyland

This is Steve. So there is flexibility around the timing of that. So basically once the last component of the project comes into service, then thereafter EEP has a year of flexibility in which to exercise that option. So we expect to finish up from of the smaller items and tankage and some other things on our Eastern Access project around midyear of 2016, and so that would afford us a year of flexibility to exercise that option after that, so roughly mid 2017. So that flexibility does exist that you point out.

John Edwards

Okay great. Thanks for that reminder. And then I was asking a number of questions on MEP on the MEP call and Greg deferred it to Enbridge. So I guess I'll just kind of start high level, if you could update us on perhaps is there potential modification to the distribution support agreement and perhaps talk about the sustainability of the EEP/MEP relationship in the current form, and if you were to modify it, when and how, so just if you could talk generally about that? And I could ask more specifics, but I'll just kind of keep it open ended for now.

Mark A. Maki

Generally, John, I think – and obviously these are – we view MEP over the long run as being an important part of the Enbridge family of companies as is EEP. So highest level, I think Company views the sponsored vehicles, the income vehicles as being an important part of the capital structure. And yes, we're in a current cycle in the environment where it seem to be out of favor but that comes and it goes, and so we're not going to do something each year on any of these vehicles. We're going to think very carefully and go through a systematic process of trying to figure out what is the best thing for all involved long run.

So as far as the EEP/MEP relationship, kind of coming back to that question, Greg has been very successful at self-help inside of MEP and you see that with the 2015 results inside the vehicle. He's been very successful at turning costs and he's been very good at getting the leadership team to find ways to be creative and basically not need a lot of help from EEP, and so that's job one. And then after that, then he considered all the other alternatives that are out there and obviously there are many and we're not going to go into the details of any of those today in how we evaluate them or look at them other than to say, we look at the Enbridge history. Enbridge has always been at the highest level a very supportive general partner to EEP and likewise to Midcoast.

John Edwards

Okay. Just following up that then, I mean we're projecting that leverage by assuming that the guidance is about right, we're projecting leverage would balloon to about 6x, 5x to 6x, depending on where in the range you are. And so that's why I was raising the question on what Enbridge would consider doing next in regard to that. I mean obviously the distribution support is throughs 2017, and so that's why I'm just, what kind of balance sheet helps or perhaps extension of distribution support are [indiscernible] in that? There's just a lot of different options on the table and I understand it's a challenging commodity price environment, but that's just what the numbers look like and so that was really the genesis of it. It just looks like that leverage metric could really balloon out and so what kind of support Enbridge would perhaps provide on that score, if that makes sense.

Mark A. Maki

Again going – in your question I think is some of the answer, but basically the first place to start is the self-help program and Greg's been very successful at executing against that program before. And then after that, a variety of different options come into play but that today is premature to discuss any of that.

John Edwards

Okay, all right, that's it for me. Thank you very much.

Operator

Our next question is from Ted Durbin with Goldman Sachs. You may begin.

Theodore J. Durbin

I want to start with liquids segment and I want to really kind of get after the [indiscernible] margins that you're looking for there. You've got volumes up. It looks like on a revenue basis you're not actually growing sort of the revenue per barrel. Then also you've got it looks like higher power costs and O&M. Maybe you can just talk through the margin profile for liquids?

Mark A. Maki

Ted, are your comments on the quarter Q4 or the…?

Theodore J. Durbin

On the guidance, yes, 2016 guidance relative to last year.

Mark A. Maki

Okay. Maybe Steve, you want to take a [indiscernible] at it and then Guy and I can supplement.

Stephen J. Neyland

Yes, sure. So I think probably the slides of reference here are going to be slides 15 and 16 in the documents provided. Here you can see the volumes that you referenced and so there is volume growth certainly from the Lakehead and certainly from an overall perspective, and fairly slightly down year-over-year on North Dakota, again that's as mentioned in the remarks, is predominantly gathering volumes. It is not the Mainline of North Dakota.

So, some of the challenges from a margin perspective are noted on Slide 16, as mentioned the gathering and rail, so you're losing that upstream volume. And additionally you've got oil prices coming off a bit. So you're losing some allowance oil dollars. And then it depends how you are doing your unit margin on that, I guess on a gross margin basis this wouldn't apply but you do have some rising property taxes which attribute to the overall operating income and DCF.

The other thing to keep in mind is, as Lakehead volumes grow, there is an element of qualifying volumes in our numbers that effectively are credited back to the shipper. So there is a component of that in the calculations. So that's at a high level, those are some of the drivers.

Mark A. Maki

And maybe I'll go up even a little bit further level from what Steve just gave you. It's probably a pretty technical question, Ted. I mean we should take it offline with Sanjay in the IR team. But basically if you're operating in a cost of service environment, a lot of our system is cost of service, you have a revenue requirement that you are recovering over the units and what you see with our forecast for next year is volume is going up. And so you're going to recover that cost of service over a greater number of units, then the unit margin is going to be a little bit lower on the component of the system that is cost of service.

So that's like an example of one of the things that you'd be looking at in the numbers that you need to kind of peel the onion to understand it there, which I think is really a follow-up conversation with the IR people. And then there are a lot of other factors that Steve alluded to that also kind of complicate the calculation to some degree.

But it is – the way to think about our system is it's largely on the liquids side, it's really two things, it's cost of service or utility [indiscernible] making equity rate-based, debt rate-based, you earn a return on both of those, you collect your cost of business and those costs are recovered across all the barrels that move on the system and then there's a component of indexed revenue which is sensitive to volume and our volumes are going up, so that's good.

System is basically full and where there are some cost elements that do pass through, as an example we highlighted property tax and other on that chart that Steve was referring to, those do go to bottom line. So that's an area that shows up on that chart. We'll be focusing our attention on it to try and get that cost performance better than what's shown there.

Theodore J. Durbin

That's all very helpful. I appreciate the detailed answer. Just coming back to the Sandpiper and Line 3, realizing something you can't really quantify the cost increases, but would you be able to pass through those costs to your shippers fully such that you're earning a similar return as what you had originally thought?

Mark A. Maki

Guy, you want to field that question?

Guy Jarvis

So on the Line 3 side of things, we have had as that project has progressed, a risk sharing with our customers as capital cost increases have manifested. There was a point, back I think it was in 2014, where we actually landed on a Class IV cost estimate, from which point forth both Enbridge and Enbridge Energy Partners are at risk for further capital cost increases.

On the Sandpiper side of things, it is a contract, don't want to get into the details too much, but at this stage of the game with the high level early indication of where we think the capital costs are going, it's going to be managed within the contract.

Theodore J. Durbin

And fair to say that that would be shared with your partner on Sandpiper as well?

Guy Jarvis

I'm speaking about it from the project perspective. So Marathon's impact as an equity owner in Sandpiper would be the same as our own.

Theodore J. Durbin

Same impact, okay, perfect. Great, and then just last one from me, just to be totally clear for financing here, your idea that you can sort of live off the revolver effectively if you need to along with some of the cash back from EEQ or is there any plans to be in the debt market at all?

Mark A. Maki

Jonathan Rose, you want to field that?

Jonathan N. Rose

Certainly we will look at the debt market as it stabilizes and would make a decision accordingly, but we don't expect to be in the equity markets.

Theodore J. Durbin

Understood. I'll leave it at that. Thank you.

Operator

Our next question is from Robert Balsamo with UBS. You may begin.

Robert Balsamo

I was hoping you could maybe help me walk through a little of the comments made earlier in regards to the call option on the drop-downs, the comment was made that they could be executed when the market condition strengthen. But then looking at, I know it's only proposed, but looking at the potential joint funding scenario on Line 3, it seems that that would give capital – or the capital remains back to Enbridge would be right enough to do the Eastern Access call option. Wouldn't that be a structure or an opportunity to execute in the weak market or would we need even a stronger market to execute on that strategy?

Mark A. Maki

I think you kind of basically answered the question with your question, which is that the two more or less match up pretty well. But the question that was asked, if for some reason liquidity were otherwise an issue, we wanted to pay down revolver, whenever we have time. So that's the benefit of the year. But what we've felt as our operating assumption here is that we're going to exercise these Access call option in 2016. Your logical source of funding is the one that you mentioned, but in the event there is something not I guess the way we expect in the capital markets, you got to think about the luxury of time.

Robert Balsamo

Great. And then just, is it possible you could elaborate a little bit, I know it's kind of asked before, the liquids question, on the losses in rail and gathering in the Bakken versus the liquids gains from what goes on pipelines? I know there was a 20 DCF roughly, if I look at the chart, roughly 20 million DCF decline but then the liquids numbers kind of consolidated.

Mark A. Maki

Maybe Guy can comment on some of the business factors that are going on and with respect to North Dakota rail and the western side of the system on the gathering side.

Guy Jarvis

So if you go back to when we conceived and built our Berthold rail facility, the competitive advantage that we had at the time is that we had gathering systems out to the western part of North Dakota that allowed those barrels to come onto our pipeline through the gathering systems, get to the rail facility and then leave the state by rail. That competitive advantage has been eroded over the last number of years as production grew much stronger than anybody expected and new rail facilities actually located themselves in the western part of the state.

So you had producer then who, where we went from having a competitive advantage of accessing them through gathering, we now have a competitive disadvantage in that they can get trucked directly to a rail facility and leave the region. So that's been the impact on the gathering side of it, is really the proliferation of new rail facilities in the western part of the state.

In terms of the rail facility itself, we had multiyear contracts that are starting to roll off at that facility. We had always known that it would be a difficult market in all likelihood when those contracts rolled off, but it's proven to be even more difficult than we had expected, particularly when you look at rail movements to the east of either Eastern Canada or the Eastern U.S.

Robert Balsamo

Okay great. Thank you very much.

Operator

Our next question comes from Jeremy Tonet with JP Morgan. You may begin.

Andy

This is actually Andy for Jeremy. Another follow-up on Eastern Access call option. It looks like in the DCF bridge, it implies the exercise of the call option in 2016 and that there is a contribution to the full-year guidance figures that you've provided guidance ranges. Are you using the overall or the annualized contribution from the option or is there some timing component within the guidance?

Mark A. Maki

Very good question. [So we had to roll it out to partial year] [ph].

Andy

Okay. And then on the co-funding arrangement with Enbridge, you just talked about it, but is it fair to assume that those two options, whether the option as well as the co-funding arrangement are mutually exclusive or is there a possibility that one could happen without the other?

Mark A. Maki

They are very mutually exclusive two different things. The Eastern Access call option is basically a done deal. The joint funding on Line 3 is in process with a special committee.

Andy

Okay. And as a follow-up to the third-party financing, has there been any discussion at the partnership level of potentially opening up projects to third-party joint venture partners to open up flexibility or is that kind of off the table for [indiscernible] days if we get there, preferring to keep things in-house?

Mark A. Maki

I think one of the great things again is being part of the Enbridge family of companies. You've got a very, very strong upstairs parent. So where we have used those joint funding arrangements with the parent, they've been very beneficial for both parties. The Sandpiper project is an example of bringing in a third party from outside to help accomplish a project that we both had a vested interest in. So we are not averse to it but it's certainly a possibility in toolkit to look at.

Andy

Okay great. And then on spending for Sandpiper and Line 3, just thinking about 2017, 2018 and 2019, is there any insight you can provide based on the lumpiness of spending allocated to each of those three years or is it too early to tell?

Mark A. Maki

It's probably a little early to tell. Certainly when you are under construction, that's when you see your big dollars, but we're really in permitting process really throughout 2016 and into 2017. So that's about as much color as we are going to give at this point.

Andy

Okay, so 2017 sounds like it's fairly, that we wouldn't be surprised up or down versus 2016?

Mark A. Maki

Yes, I'm going to sidestep the question for the time being, just it's we've got a little bit of process we need to work through before we give a lot more color on spend profile on those two projects.

Andy

Okay. And then final question just on leverage and actually more of a family question, but what level is EEP comfortable taking leverage to given obviously the preference to maintain investment grade, and does the fully consolidated leverage profile at ENB play any type of role in that decision?

Mark A. Maki

Jonathan, you want to field that, please?

Jonathan N. Rose

Sure. Certainly we look at – there are a number of different ways to look at leverage based on the ways that each of the rating agencies look at things. We are representing leverage here at 4.6, which takes into account 50% of the hybrid instruments. I think we would look to manage that leverage to below 5 or just into 5. Some of the other rating agencies, Moody's in particular, proportionately consolidate things and allocate different amounts of equity to different instruments. So their leverage metric evaluation would be higher.

On a consolidated basis, I think that the entire Enbridge family is looking for leverage metrics that are consistent with not only our investment grade profile, but taking into account as we've tried to spend some time here about the quality of the cash flows that underpin the investments and the lack of variability and predictability that we can establish through that. But – I'll pause there.

Andy

Great. That's very helpful. Thank you.

Operator

[Operator Instructions] Our next question is from Sunil Sibal with the global securities. You may begin.

Sunil Sibal

Couple of questions from me in terms of OpEx assumptions for 2016, I was wondering what kind of gas prices that you factor in for those assumptions?

Mark A. Maki

Steve, you want to field that?

Stephen J. Neyland

Sunil, when you say gas prices, are you referring to like gas at the pump or are you referring to, as it relates to OpEx in fields locations?

Sunil Sibal

I was presuming that it's primarily driven by natural gas and power prices. So I was kind of wondering, what's the assumption for the natural gas price for those power costs?

Stephen J. Neyland

Yes, sure. And maybe just for everybody's reference, in our supplemental slides we have some key guidance assumptions on Slide 8 of the supplemental, and there we talk about kind of this total EEP O&A of $890 million to $950 million, which on a broad basis is similar numbers to 2015 will be about $870 million. And then included within that is the power. So you see our power cost of $335 million to $355 million.

So we are assuming from a power perspective, we are running the system harder, so we're going to be with additional volumes we are using more power, there's a lot of opportunities on that side of working with utilities as well as costs such as drag reducing agent and other things that we can look to push down. So there's an element to that built in, Sunil, but I would say that whether it's that or whether it's putting gas in the trucks for the many tracks that we've got across the gas and the liquids systems, we're looking at that and looking to do better and drive that down as we look through, push through 2016.

Sunil Sibal

Okay, that's helpful. And then it seems like integrity spending in 2016 is probably going to be up year-over-year and I was wondering if you can just remind us of how should we think about the return on that investment.

Stephen J. Neyland

I think you're probably referencing, on Slide 17 you're probably referencing the liquids integrity capital that we have there, and it depends on a number of factors, but approximately half of that gets recovered on a cost of service basis through our FSM surcharge on the Lakehead system. So that's where a good component of that goes. It's fairly similar number from prior years.

Sunil Sibal

Okay, that's helpful. And then lastly, in terms of [indiscernible] cash flows, as I think about 2016, how should we be kind of thinking about Q1 through Q4 movement of DCF and adjusted EBITDA?

Mark A. Maki

I think we would tend to stay away from the kind of quarter to quarter shaping, but all I would say is, like you see with the others this quarter, our fourth quarter last year, you've got some heavier expenditures at the end of the year. So if there is any seasonality in the system, it probably tends to be, it's driven around maintenance. Keep in mind a lot of our system is where it's cold and snowy, so maintenance tends to be in the summertime. And then from a refinery turnaround or supply turnaround, those tend to be in the warmer weather seasons or when the refineries are in gasoline filled season and so forth. So you think about refinery seasonality and where our systems or liquids systems, in particular, operate.

Sunil Sibal

Okay. And then just last housekeeping one from me, in terms of Line 3 replacement, how much has been your capital spend so far on that project?

Mark A. Maki

We have to have Sanjay check the details on this, so maybe I will give you something to fall back on, but I believe it's in the order of $300 million.

Stephen J. Neyland

That's correct, Mark. So if you were to kind of piece together some of our other external information we've had, we've spent approximately $300 million [indiscernible] 12/31.

Sunil Sibal

Okay, that's all I had. Thanks guys.

Operator

Our next question is from Sharon Lui with Wells Fargo. You may begin.

Sharon Lui

Just a follow-up on that line replacement spending, for the joint funding scenario, is it just a proportionate share that's being contemplated based on the $350 million, like what should we think about in terms of the additional interest ENB would have in that project?

Mark A. Maki

We're going to probably stay away from what their percentage interest is going to be, because it would be pre-supposing what the process is going to come out of from that. We had to make an assumption obviously in doing the guidance but we want to keep that to ourselves, at least at the moment, Sharon, if that's alright. We'll have some additional spending on the Line 3 work because we're in the regulatory process in the state of Minnesota. There's probably some long [indiscernible] that we have to order. Right now that's all, that $300 million that was mentioned, that's all EEP paying for that. And so what would happen is you'd have – Enbridge would buy end of the project, if you will, contribute capital and assume a particular ownership interest.

Sharon Lui

And with ENB I guess going forward, I guess take the allocated, the proportionate share of CapEx going forward for that project based on that interest as well?

Mark A. Maki

Yes, we kind of treat it like a joint venture.

Sharon Lui

Okay. And with regards to I guess the potential delay in timing of Sandpiper and given the current commodity environment, maybe just your updated thoughts on the project itself as well as I guess the ability for Marathon to potentially change its commitments given the I guess increased potential cost and delay in timing of the project?

Mark A. Maki

Guy, can you field that?

Guy Jarvis

So, a couple of comments in response to that. So first and foremost, we continue to be very positive about Sandpiper. I mentioned earlier in the call what we're seeing today not only out of North Dakota but across our Mainline is validating our premise that our market access projects have attached the highest netback markets. So we don't see that changing going forward in North Dakota in terms of our competitiveness.

I think in terms of Marathon and the Sandpiper contract, again all I'm going to say is that there is nothing that we're seeing based on this delay or a high level unclassified look at what it might mean for our capital costs that has a material impact through the contract.

Sharon Lui

Okay, thank you. And I guess just one housekeeping item. For coverage guidance for 2016, does that just assume flat distributions for the balance of the year?

Mark A. Maki

In the current environment, Sharon, I think what we're going to guide to on this is we have always been an annual evaluator I guess of distribution coverage, and of course it's a quarterly decision what your payout is going to be, but I think it would be fair to assume in 2016 we're not going to raise the distribution.

Sharon Lui

Okay, thank you.

Operator

Thank you. I'm showing no further questions at this time. I'd like to turn the call back over to Sanjay Lad for closing remarks.

Sanjay Lad

Great. Thank you, Sharon. We appreciate your interest in Enbridge Partners and thank you for participating on today's conference call. I would like to remind you that I will be available for any follow-up questions you may have over the course of the next couple of days. Thank you and have a great day.

Operator

Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day.

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