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

Q4 2013 Earnings Call

February 13, 2014 9:00 am ET

Executives

Sanjay Lad - Former Director

Mark Andrew Maki - Senior Vice President of Enbridge Energy Company Inc, Director of Enbridge Energy Company Inc and President of Enbridge Management

Stephen J. Neyland - Vice President of Finance - Enbridge Energy Company Inc and Vice President of Finance - Enbridge Management

Stephen John Wuori - Executive Vice President of Liquids Pipelines - Enbridge Energy Company Inc, Director - Enbridge Energy Company Inc, Executive Vice President of Liquids Pipelines - Enbridge Management, President of Liquids Pipelines of Enbridge and Director - Enbridge Management

Darren Julian Yaworsky - Treasurer - Enbridge Energy Company Inc and Treasurer of Enbridge Management

Analysts

Stephen J. Maresca - Morgan Stanley, Research Division

Brian J. Zarahn - Barclays Capital, Research Division

Mark L. Reichman - Simmons & Company International, Research Division

Theodore Durbin - Goldman Sachs Group Inc., Research Division

John Edwards - Crédit Suisse AG, Research Division

Shneur Z. Gershuni - UBS Investment Bank, Research Division

Sharon Lui - Wells Fargo Securities, LLC, Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Quarter 4 2013 Enbridge Energy Partners Earnings Conference Call. My name is Patrick, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Sanjay Lad, Director, Investor Relations. Please proceed, sir.

Sanjay Lad

Thank you, Patrick. Good morning, and welcome to the 2013 Fourth Quarter Earnings and 2014 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 website at enbridgepartners.com. A replay will be available later today and a transcript will be posted to our website 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 Mark Maki, President; and Steve Neyland, Vice President, Finance. Available for the Q&A session, we also have Steve Wuori, President, Liquids Pipelines, Enbridge, Inc.; Greg Harper, President, Gas Pipelines and Processing, Enbridge, Inc.; Terry McGill, Senior Vice President, Operations and Engineering; Darren Yaworsky, Treasurer; and Noor Kaissi, Controller.

Moving forward to our legal notice. This presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and the Partnership's SEC filings and we incorporate those by reference for this call. This presentation also contains 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 website. Please turn to Slide 3. I will now turn the conference over to Mr. Mark Maki, President.

Mark Andrew Maki

Thank you, Sanjay. Good morning, and welcome. We're changing the order on this quarter's call. Steve's going to start our call with a review of the fourth quarter results. I will then cover the key messages we've been hearing from our investors related to project status, our funding plans and equity needs and our plans for Midcoast Energy Partners. Steve will close the call with a review of the partnership's financial guidance for 2014.

Before I pass it along to Steve, we'd like to recognize the appointment of Greg Harper to the leadership team of our Natural Gas business at Enbridge. Greg brings deep natural gas midstream experience and strategic insight to his new role of President, Natural Gas Pipelines and Processing, Enbridge Inc. and Principal Executive Officer of Midcoast Energy Partners. We are excited to have Greg working with us at Enbridge. Please turn to Slide 4. Steve?

Stephen J. Neyland

Thank you, Mark. Fourth quarter adjusted net income of $73.1 million was $14.1 million lower than the same period of 2012. Higher revenues associated with stronger deliveries, increased transportation rates and earnings contributions from growth projects placed into service, our Liquids business was more than offset by a combination of the inclusion of the accrued deferred distribution of $22.4 million attributable to preferred unit holders for the preferred units issued in the second quarter of 2013 and also, lower NGL and volumes impacting the margins in our Natural Gas business. Full year EBITDA of $1.14 billion came in below our 2013 EBITDA estimate of $1.18 billion to $1.2 billion we discussed at our third quarter call. Our fourth quarter results came in below our updated forecast due to a few factors. Strong deliveries on our liquids pipeline systems and the incremental contribution from growth projects recently placed into service in the fourth quarter was more than offset by a combination of the higher than forecasted integrity cost-related to the Line 14 hydrostatic test we completed in the third quarter.

Also, extreme weather conditions in the Texas Panhandle region that resulted in a producer freeze offs and unplanned maintenance which negatively impacted the margins in our Natural Gas business, as well as lower natural gas and NGL volumes in the Natural Gas business. Adjusted earnings per unit for the fourth quarter were $0.12 compared to $0.18 for the same period 2012. Lower adjusted earnings attributable to limited partner interest due to the deferred distribution on the preferred units, coupled with the increased weighted average number of units outstanding in 2013, compared to fourth quarter of 2012, resulted on lower earnings per unit when compared to the prior year. We have presented our as-declared coverage ratio, both on a cash and assuming inclusion of the paid-in-kind distribution, which were 0.82x and 0.7x, respectively, on a year-to-date basis. We expect our coverage ratio will improve as we continue to place additional assets from our multibillion dollar organic growth program into service. Collectively, these projects will deliver long-term, low risk, secured cash flows for the Partnership.

I'll discuss this further later in the presentation. At the end of the year, we had approximately $2.6 billion of available liquidity. The Partnership now has an excess of $3 billion of credit facilities to provide enhanced financing flexibility as we execute on our organic growth program. We are committed to maintaining our strong investment-grade credit rating.

Please turn to Slide 5. For our liquids segment, adjusted operating income of $185.8 million for the fourth quarter was $52.8 million higher than the same period from 2012, and $35.6 million higher than the third quarter of 2013. Compared to prior year, fourth quarter operating revenues increased due to increase in transportation rates on our Lakehead system and the North Dakota systems and contributions from growth projects entering service earlier in the year. Specifically, from the Bakken Berthold Rail and Bakken Pipeline expansion projects.

Higher revenues during the quarter were partially offset by higher pipeline integrity cost, increased property taxes and workforce cost. During the fourth quarter, we incurred approximately $10 million in cost associated with the scheduled hydrostatic test on our Line 14, which was offset by approximately $12 million recovered in our tariffs during the same period. The year-to-date revenues collected in our totals for this initiative was approximately $35 million with actual cost incurred of approximately $57 million. Resulting in a timing difference of approximately $22 million between integrity cost incurred and the related recovery of these costs on our tariffs. We expect the remaining cost will be recovered in our tariffs in future periods.

Now turning your attention to the chart on the right. We are pleased with the continued improved deliveries on our liquids pipeline systems during the quarter. Deliveries on the Lakehead system improved to 1.92 million barrels per day during the fourth quarter, which was 4.9% higher than the current quarter over the third quarter of 2013, due to supply growth out of Western Canada, Lakehead expansion projects and refineries emerging from scheduled and unscheduled maintenance.

Deliveries on our North Dakota system of 200,000 barrels per day were slightly lower than third quarter of 2013. During the quarter, we increased our total cost estimate related to the Line 6B incident by $87 million to $1,122,000,000 to reflect increased dredge activity in and around Morrow Lake in the Delta area. The $87 million increase is inclusive of the $22 million amount disclosed earlier in the fourth quarter related to the civil penalties accrued to date under the Clean Water Act of the United States. The cumulative amount collected from insurance recoveries is currently $547 million and we expect to recover the balance through our aggregate liability insurance program of $103 million. This will come from our insurers in future periods. Through the end of 2013, we spent approximately $860 million on Line 6B remediation and had a remaining estimated liability of approximately $260 million.

Please turn to Slide 6. Adjusted operating income of $4 million for the fourth quarter in our Natural Gas segment was $38.9 million lower than the same period in 2012. The decrease in the fourth quarter Natural Gas adjusted operating income over prior year was primarily due to lower NGL prices, lower natural gas and NGL volumes on our systems and operating headwinds that impacted us in the fourth quarter. Lower NGL volumes are the result of ethane rejection experienced in some of our plants situated in the Mid-Continent. Our Anadarko system results were negatively impacted by the tightening of the spread between Mont Belvieu and Conway priced NGLs when compared to prior year.

These trends are consistent with what we observed during the third quarter.

A few notable operating headwinds during the fourth quarter negatively impacted adjusted operating income, extreme weather in the Texas Panhandle region during December, which resulted in producer freeze offs, coupled with unplanned downtime at 1 of our plants contributed to the volume decline across our systems and lower earnings forecasted for the fourth quarter. Let's move to Slide 7 and I will now turn it back over to Mark to touch on the highlights in 2013 and discuss the Partnership's growth outlook.

Mark Andrew Maki

Well, thank you, Steve. To start I'd like to spend a few minutes to highlight the significant progress the Partnership achieved and some of our core objectives in 2013 and then to address a few key points on the mind of our investors. At a high level, market fundamentals, supply, demand and competition, especially in the form of rail transportation made 2013 a challenging year. The fundamentals will continue to change and we believe will support a return of higher volumes in our North Dakota system, along with further expansion of that system in the form of our Sandpiper project and we'll talk about that more in just a minute.

Volumes in the Lakehead mainline were less than expected, primarily as a result of customer refinery and reconfiguration projects that were -- it took longer than expected. That is also a transitory matter. With supply continuing to grow, our expansions and those of Enbridge Inc. coming into service, we will see volumes grow on our systems. Finally, separating our Gas business into its own Partnership will allow that business to grow successfully with consistent access to capital. And it intends to help Midcoast be successful with consistent drop downs of its remaining interest in the Gas business over the next several years.

Finally, we expect improved earnings and distribution coverage in 2014. This will result from full year earnings and cash flow contributions from organic growth projects, which recently entered service, supplemented with additional growth projects that entered service in 2014. I want to cover up a couple of areas of importance to the company. First though, the safety and operational reliability, and these are core values of Enbridge. We're working very hard on delivering in our commitment to achieve industry leadership in pipeline system integrity and safety. We continue to make operating and capital investments to achieve this objective. One example is our Line 6B 75-mile replacement project that was placed in service with the full-line replacement scheduled to enter service over the course of 2014. When this project is complete, our ability to move oil to the East will substantially increase and we'll have completely replaced the pipeline from Chicago, Illinois to the border crossing at Sarnia, Ontario.

On the project execution front, we made significant progress advancing our Partnership's multibillion-dollar organic growth program, our major projects team continues to deliver these projects largely on time and on budget. As examples, during the year, we substantially expanded our infrastructure footprint in the North Dakota Bakken region. First, our Bakken Pipeline Expansion or BPP [ph] and the virtual rail facility were placed in service and provided incremental takeaway capacity from the region of 145,000 to 80,000 barrels a day, respectively.

Our Bakken Access project enhanced the [indiscernible] capabilities of our North Dakota system by 100,000 barrels per day through the addition of gathering and truck unloading facilities. We also significantly enhanced or advanced our Eastern Access program. We completed the expansion of Line 5 providing an incremental 50,000 barrels per day of capacity from Superior, Wisconsin into Sarnia, Ontario and we placed into service our Line 62 Spearhead North pipeline expansion which increases the line's capacity from Flanagan, Illinois to our terminal at Griffith, Indiana by 105,000 barrels per day.

These expansions and the additional phases of expansion we have entering service over the 2014 to 2016 timeframe are essential to the debottlenecking of North American crude oil markets. And these will effectively provide more capacity where it's needed. Selectively, the Partnership's placed in service over $1.8 billion of organic growth capital. As you'll see from our financial outlook for 2014, these projects will provide a meaningful contribution to enhanced earnings and cash flows for the Partnership in 2014 and beyond.

During the financial execution, funding our growth program is a major focus for management and what was accomplished in 2013 significantly moderates the amount of equity we expect to need over the next 4 to 5 years. Five actions undertaken in 2013 meaningfully address this objective. First, the $1.2 billion preferred unit private placement. Second, exercising the option to put a portion of our Lakehead expansion projects and the associated funding to our parent. Third, the accounts receivable securitization. All 3 of those highlight the tremendous value the Partnership realizes from having Enbridge, Inc. as our sponsor and parent. We also completed a public secondary equity issuances. And finally, the notable the event is the Initial Public Offering of Midcoast Energy Partners. And I'll expand on Midcoast strategic importance in just a minute.

Moving forward to Slide 8 and financing outlook. When the Partnership announced its multibillion-dollar organic growth program in 2012, the markets understood we needed a lot of funding. Based on the collected financing actions summarized in the last slide, management of the Partnership has made significant progress addressing the financing overhang that we believe is impacting the Partnership's unit price. We satisfied over $3 billion of funding needs through the actions we just discussed. As you can see from the chart on Slide 8, our equity funding requirements are minimal and our remaining equity needs over the 4-year plan is quite modest. Thus, we have financing capacity for future accretive organic growth projects and acquisitions or exercising of our call rights on some of our expansions as needed.

Please turn to Slide 9. Over the last couple of years, our crude oil supply growth has outpaced development and pipeline infrastructure and this is one of the fundamentals that we were challenged by in 2013. Constraints in transportation infrastructure, coupled with continued supply growth has resulted in substantial pricing discounts for crude oil. The market access programs announced by Enbridge and the Partnership are part of a strategic initiative to address these bottlenecks and unlock the best markets in the U.S. Gulf Coast, the East Coast, Midwest and Eastern Canada. In the process, we are matching growing North American supply to markets that have traditionally been served by foreign offshore imports. When you look at the map, the Partnership's Lakehead system is at the heart of the pipeline crossroads in North America, and our systems provide the greatest degree of market optionality and this differentiates our pipelines from those of other companies.

Before I move on to the next slide, I want to point out a couple of projects that will be entering service in 2014. First, the Partnership will benefit from a large phase of our Eastern Access project entering service. The Line 6B 210-mile replacement project will begin service expanding the line's capacity from 240,000 barrels a day to 500,000 barrels a day between Griffith, Indiana and Sarnia, Ontario.

Turning to the mainline expansions. The permitting process for our Line 67 expansion is progressing slower than planned. However, we are implementing temporary system optimization actions, which will enhance our capacity in the interim and substantially mitigate volume impacts. Our Line 61 expansion is progressing on schedule and will enter service in the third quarter and complement Enbridge's expanded corridor to the Western U.S. Gulf Coast via the planning in south and Seaway pipeline twin expansions.

Please move on to Slide 10. A key development during the fourth quarter was our announcement that the Partnership had secured Marathon Petroleum Corporation as an anchor shipper for the Sandpiper project. Marathon will also fund 37.5% of the project's construction in exchange for an approximate 27% ownership interest in the Partnership's North Dakota systems, which Sandpiper will become part of once it's placed in service in early 2016. The Sandpiper project will expand and extend the Partnership's North Dakota feeder system. The expansion of all of the construction of the 24 inch diameter line for Beaver Lodge, North Dakota to Clearbrook, Minnesota and a 30-inch diameter line from Clearbrook into Superior, Wisconsin, adding 225,000 barrels a day of capacity on a twin line between Beaver Lodge and Clearbrook and 335,000 barrels a day between Clearbrook and Superior.

Sandpiper is a key part of our Light Oil Market Access Program. When complete, the program will provide an additional 400,000 barrels per day of light crude oil access to premium price markets in Ontario, Québec and Patoka, Illinois. And access to Patoka, the Southern Access Extension project is of particular importance, is light crude, we'll now be able to access close to 800,000 barrels per day of refining capacity that previously cannot be served through the Partnership's mainline system. We recently concluded the open season and we obtained sufficient commitments to allow the project to proceed.

Please turn to Slide 11. In the fourth quarter, we closed the Midcoast Energy Partners, MEP, Initial Public Offering. This transaction was completed for several reasons. First, EEP wants the gas business to grow and be successful. In the near-term, enhanced access to capital for gas business is necessary to achieve that objective. Second, the drop down program to Midcoast will provide an additional source of capital for EEP to fund our liquids pipeline's organic growth program.

Drop downs are an important source of momentum for Midcoast and EEP and EEP is more incentivized to make it happen. To that end, we expect that we will complete a further drop down of ownership interest in the natural gas business to Midcoast by mid-2014. Over the next few years, we expect that EEP will sell all of its gas business ownership interest to Midcoast. We see the series of drop downs as an important source of equity capital for EEP. As the earnings and cash flows of Midcoast Partners grow, we will also benefit from the perspective growth in the incentive distribution rights that we own as a general partner of Midcoast. Let's move forward to Slide 12. I'll turn the call back over to Steve to present the '14 financial outlook.

Stephen J. Neyland

Thank you, Mark. For 2012, we estimate the Partnership's adjusted EBITDA will increase by approximately 30% and will be between $1.5 billion and $1.6 billion. Operating income is estimated to be between $1.05 billion and $1.13 billion, with approximately 90% contribution from our Liquids business and 10% from our Natural Gas business. We expect depreciation will be between $440 million to $480 million. The Partnership expects to place an additional $1.8 billion of organic growth projects into service in 2014. We will benefit from a large phase of our Eastern access project entering service, the Line 6B 210-mile replacement project will begin service expanding the line's capacity from 240 a day to 500,000 barrels per day between Griffith, Indiana and Stockbridge, Michigan, in late Q1, and between Stockbridge and Sarnia, Ontario in the third quarter.

Additionally, Phase I of our Line 51 expansion will increase the line's capacity by 150,000 barrels per day between Superior, Wisconsin and Flanagan, Illinois, is due to begin service in the third quarter. These projects, which are complemented by full year contributions from projects that were placed in service in 2013, we forecast the Partnership's EBITDA growth will trend or accelerate as depicted in the chart on the top right of the slide.

Distribution coverage is expected to improve to between 0.85x and 0.95x, with cash coverage to range between 1.05x to 1.15x. The long-term, low-risk commercial underpinnings of these accretive growth projects, such as cost to service and take or pay structures, provide us with a high level of confidence in progressive distributable cash flow growth and improving coverage, which supports our target annual distribution growth rate of 2% to 5%.

Please turn to Slide 13. Here, we present our volume forecast for our Liquids and Natural Gas businesses that was used to develop our forecast for 2014. We expect total Liquids pipeline systems volumes to increase over 2013 with continued production out of Western Canada, complemented by increased downstream demand, along with the organic growth projects scheduled to begin service in 2014. We anticipate strong system utilization with average deliveries of approximately 2 million to 2.2 million barrels per day on our Lakehead system.

As it relates to our North Dakota system, with the combined ship or pay volumes on the Bakken Pipeline expansion that were placed into service in March 2013, and our existing North Dakota pipeline, we forecast our North Dakota volumes to grow to between 326,000 and 336,000 barrels per day. Although competition from rail transportation lessened during the second half of 2013 due to tightening of crude oil price differentials between waterborne and inland prices, there still remains a competitor to our pipeline in the region. We believe the North Dakota system volumes will continue to improve later in the year as pipeline expansions and enhanced market access to Eastern Canadian markets and Eastern PADD II markets are expected to decrease crude oil price differentials.

In our Natural Gas business, overall system volumes are forecasted to remain steady through 2014. Annualized volumes on Anadarko system are expected to decrease slightly in 2014 being the loss of a major customer on the system. However, we expect volumes at Anadarko system will ramp up over the course of the year as we expect development of the Granite Wash play to continue due to the prolific nature of the wells, current market prices for NGLs and crude oil. We expect ethane rejection to continue to persist predominantly at some of our assets on the Anadarko system at levels comparable to 2013. We expect volumes in East Texas to remain steady in 2014 due to the moderate level of drilling activity for dry gas and forecasted natural gas pricing environment and increased drilling in the basin by customers pursuing rich gas formations using horizontal drilling and multistage fracturing. Volumes in North Texas are expected to remain flat in 2014 with activity heavily focused on development of oil resources in the region. Our supplemental slide deck provides additional detail to support our 2014 outlook.

Please turn to Slide 15. This slide provides our 2014 capital expenditure forecast, which is estimated to be $1.66 billion and is inclusive of approximately $110 million for core maintenance. These expenditures are presented net of joint funding. Please turn to Slide 14 and I'll turn the call back over to Mark for his closing remarks.

Mark Andrew Maki

Thank you, Steve. Just a couple of brief points here in closing. First, we expect improved performance in 2014. Second, we made substantial progress addressing the Partnership's long-term financing needs. This means our future equity needs are going to be very manageable and that leaves plenty of room to pursue organic growth opportunities or acquisitions and includes potentially calling back interest in EA and ME.

Finally, I want to talk about distribution. Distribution news was in the markets this week, so let me start with our view that management believes each distribution is secure. Executing against our long-range plan is what we always do at Enbridge. And if we execute against that plan, our coverage will improve, our distribution will increase. Our confidence in this view comes from the nature of our pipeline business and cash flows. Our cash flows are predominantly underpinned by low risk cost of service and fee based revenues. Our organic projects are largely back stock by long-term low-risk arrangements, such as cost to service or take-or-pay. These projects will deliver visible and highly certain earnings and cash flows when they enter service. With that, I'd like to turn the call over to the operator for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Stephen Maresca with Morgan Stanley.

Stephen J. Maresca - Morgan Stanley, Research Division

On Sandpiper, I just want to ask a couple of questions. Mark, you talked about moving forward. Can you give a little more color on terms of what sufficient approval means with respect to percent of the design capacity that's going to be initially contracted? Also, what additional, if any, regulatory approvals are needed, and then final, can you just remind us how much EEP own to that right now or will own on it?

Mark Andrew Maki

Sure. Stephen, the way to funding big ticket reverse order, and I'll ask Steve Wuori, to add some additional color. But the plan is for Marathon to fund 37.5% of the project and in the process of doing that, what they're also effectively doing is funding an acquisition of a piece of our existing system. So when all is said and done, they will own approximately 27% of the North Dakota system. So that's the first element. With respect to the amount of the volume that's been up-ticked in the open season process, it is sufficient and enough for us to proceed. We're not going to give an exact number at this point. There will be some capacity available for spot shippers and so as our next step that we need to go through, we'll be going back to FERC with -- or have gone back to FERC with a filing going through our plans for the asset. So that's kind of a quick summary to your 3 questions. Steve, anything to add to that?

Stephen John Wuori

Well, I think that's good. We did file the PDO, the Petition for Declaratory Order, which is the FERC filing. And then other approvals would be North Dakota and Minnesota and Wisconsin state approvals for the actual construction. All of those are moving along quite well.

Stephen J. Maresca - Morgan Stanley, Research Division

Okay. Final on Sandpiper, you're spending $315 million in 2014, just a broad breakdown of what that's on?

Mark Andrew Maki

A lot of it would be, effectively, commitments for pipe, land, right away, the engineering design, that kind of activity, Stephen.

Stephen J. Maresca - Morgan Stanley, Research Division

Okay. You had a little bit decline in the Liquids segment in North Dakota and Mid-Con. How much did weather impact that, if at all?

Stephen John Wuori

It's Steve, Stephen. Good names this morning. The -- yes, I don't think weather was so much of a factor. What's really bounced around is the rail optionality and the attractiveness of rail. We've seen that come back now, and so I think as our guidance would suggest, we do see that coming back quite strongly in 2014. But rail is always the flywheel that people will use to ensure that they move to the markets that they see to be the most attractive. But we are seeing some return to pipe attractiveness. And I think, especially, the markers to watch for are when we open up our Flanagan South expansion and then the Line 9 expansion a little bit later in the year, I think that's where the pathways for Bakken crude will really start to take hold. That's -- part of what has driven the rail movements is that there haven't been good markets to go to, at least not enough of them, on pipelines, and we are addressing that especially through those 2, and then, of course, later on, as we look into 2016 and so on. So that access extension down to Patoka will feed the Eastern PADD II refineries and give the strongest pathway for Bakken out in that timeframe.

Stephen J. Maresca - Morgan Stanley, Research Division

Okay. Great. I appreciate that. And then final one for me. And I appreciate the color, Mark, you gave on the distribution. And you have the 2% to 5% CAGR coverage this year, about 0.9% overall. Is it -- is the idea that you won't go increase that until you get over that 1-times coverage, and we should be thinking about it as a long-term CAGR, but in the near term, flat until you get -- until we see sufficient coverage?

Mark Andrew Maki

I think, Stephen, we really want more flexibility than that, frankly. And what we look at is our long-range plan is really our compass for how we run the company. And so as we see improvements in performance and we're executing the plan, management would be -- certainly could bring forward a distribution increase earlier than when we get to 1 to 1 coverage. But, of course, always those increases are subject to Board of Director's approval. But I think if we execute against our plan, and that is our expectation of what we're going to try to accomplish as a management team, there's no hard and fast rule that says we can't increase until we go up at 1.

Operator

Your next question comes from the line of Brian Zarahn with Barclays.

Brian J. Zarahn - Barclays Capital, Research Division

On expansion CapEx, it appears that spending may have peaked in 2013. So relative to 2014 guidance, about $1.5 billion, how do you view 2015 and 2016 levels?

Mark Andrew Maki

It would probably be -- Brian, that same kind of general time zone maybe a little bit more, a little bit less. But that's -- we'll probably, certainly provide more color on future CapEx as part of our EPA coming up here in early April. I think for purpose of your modeling, kind of in that same general time zone, that's probably a good set of numbers.

Brian J. Zarahn - Barclays Capital, Research Division

And then -- and a related question. Assuming the MEP drop-down progresses as expected, how do you view your remaining equity needs for this year? And would you look probably more likely to tap the ATM, or how would you view the remaining needs?

Mark Andrew Maki

Well, certainly ATM remains an option for us, but we do expect our equity requirements to be quite modest. Looking at what we showed you in the slide is really over a 4-year period, and you see the total there. We did a lot of work in 2013 to knock off our equity requirements. So I think what we have, locking, specific on the numbers is pretty modest, very doable in 2014. Darren, anything you want to add to that?

Darren Julian Yaworsky

I think you covered it all.

Brian J. Zarahn - Barclays Capital, Research Division

Okay. And a final one for me. I would appreciate Steve's views on a potential change of, probably, not for quite some time, but potential change in the U.S. crude oil export policy and what -- if any impact would be on EEP's system?

Stephen John Wuori

Well, that's a deep question, Brian, for sure. And it certainly is one that's going to be bubbling around in 2014 pretty extensively. I don't know that we think there's going to be any big epiphany in 2014 around crude exports. Of course, product exports continue to soar, and so you could argue that the volumes actually are moving. It's just a matter of the form that they take. Probably, the most likely crude to increase exports might be ANS, off the North Slope of Alaska, with the Fairbanks refinery planning to close. There's more ANS available. So it's going to be interesting to see how that dynamic all works out. However, with regard to the partnership system, I think that the access that we're putting in to Houston and Port Arthur and the dock capacity that we have there will all play into -- regardless of the "export debate," which is to countries other than Canada and Mexico, of course, those move quite freely. We're already seeing substantial movements from the Texas Gulf Coast to Louisiana, to Philadelphia, to Eastern Canada, and so I think a lot of that business is going to go on and should benefit the partnership by virtue of the pull-through volumes to feed those needs. So I think, all in all, it's favorable to the partnership, but I don't know that we're looking for any big breakthrough in the middle of an election year.

Operator

Your next question comes from the line of Mark Reichman with Simmons.

Mark L. Reichman - Simmons & Company International, Research Division

Just a couple of questions. First on the North Dakota system, it did 200,000 barrels per day in the fourth quarter. You're kind of projecting a range of 230,000 to 250,000 in '14. I was just curious, where do you see that ending up at year end 2014?

Stephen John Wuori

I think it's pretty hard to know what an exit rate is going to be just due to the -- it isn't always linear and it's due to a lot of factors, including upstream and downstream disruptions, rail and so on. I don't know that I would try to hazard a prediction as to what the exit rate is going to be. I would say, generally speaking, though, you can look at the range that we've given and consider the higher end to be what is likely at the end of the year just because of the additional market access available, particularly for light Bakken crude to the Montréal and Québec City markets, with Line 9 opening up at 300,000 barrels a day sometime in the fourth quarter. So I think that's what I would look to is that we're likely to be in the upper range there, with a couple of those step changes for market access taking place in the year.

Mark L. Reichman - Simmons & Company International, Research Division

Okay. And with regard to your capital investment program, Sandpiper's $2.6 billion. You had mentioned $300 million-plus being spent in 2014. What kind of visibility do you have on costs? I mean, how confident are you that you're not going to experience significant cost creep? And then, I guess, also related to the capital investment program, how do you think about the timing on these MEP drop-downs? I think during the call yesterday, on the Midcoast Energy Partners call, you had mentioned the $300 million to $500 million drop-down this year. But how do you get to that $2.6 billion, I mean, weighing the impact on EEP versus what the market will bear in terms of the drop-downs?

Mark Andrew Maki

Maybe I'll take a crack at that, Steve, and then ask you to help me out as my voice is starting to go. But the -- first off, the degree of confidence we have in our estimates is very good. One of the absolute great things you get with being part of Enbridge is a very, very robust, very skilled major projects execution group. And before we ever go forward to the Board of Directors, we've got a lot of work done on the cost estimates. We've been building, of course, a lot of pipelines across North America for a number of years. And we have managed big projects like this before. This is not something the first time we've done it. And so we've got the capability. We've got the procurement, the engineering design, the ability to execute on the construction. All the infrastructure required to manage the project as it unfolds. So we've spent actually quite a bit of time describing that process at Enbridge day in and each day over the years. That's what gives us confidence, Mark, in the $2.6 billion being a good number. And when you look at some of the Enbridge Inc. materials, comes a very comprehensive list of all the projects we've got going on in the company. You'll see very, very few that are delayed or over-budget. Generally speaking, it's on time, under budget, is what you see. So our history, our track record tells us that we're pretty good in getting those numbers. As far as the drop-downs of $300 million to $500 million, the sizing of that is going to be somewhat dependent upon what we need as far as capital of EEP during the year, so that range is a little bit on the broad side. And -- but our -- we really have a strong desire to drop down the gas business to Midcoast. It's an important part of helping that business to be able to hit distribution growth targets. And at EEP, we are driving, over the long run, to get the gas business into its own MLP, with EEP as a general partner. That's where we want to get in the 4- to 5-year timeframe.

Mark L. Reichman - Simmons & Company International, Research Division

And then the last question, and these are both ENB projects, but could you remind me on the timing of the Seaway twin going into service versus Flanagan South?

Mark Andrew Maki

Mark, it's going to be quite similar, middle of 2014, and that matches up well with the commitments that we have all the way through from Chicago to Houston.

Operator

Your next question comes from the line of Ted Durbin with Goldman Sachs.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

I want to start on Lakehead, please, and the volume forecast there, which is obviously up a lot for '14 versus '13. Can you just give us some details around how much of that is some of the refining -- the increase in refining demand, with maybe Whiting and whatnot, or is it more of the projects in service, just kind of help us bridge that big growth rate you're seeing in '14?

Mark Andrew Maki

Sure. I'll take a little bit of that and then, Steve, of course, who lives and breathes this everyday. But the -- a lot of it, Ted, is going to be driven by supply growth, and some of the projects that were completed in '13 in the Oil Sands side basically kind of hitting there. Maybe they got the kinks worked out and then hitting their stride on their production. Projects like that the Kearl project that IOL has, Kirby Lake for CNRL, amongst others. And so when you look at those projects and you look at the ones in '14 that are scheduled to come online, Husky, Cenovus and IOL, all have pretty meaningful additions. So we see a growth in supply of about 400,000 barrels a day. So that's one big driver. And the other is, of course, if you touch on the refineries coming out of turnaround, and Whiting is, of course, a big one. And maybe, Steve, any additional color to add?

Stephen John Wuori

No. I think that's really the story there. BP is in the middle of the ramp-up of the big Whiting conversion project, the heavy, and that's moving along. They'll have to speak to exactly what pace they expect to see to the full -- the completion of that. But I think that's the big factor, especially for heavy oil. When you recall that in the later part of 2013, we had an issue where they're just were in not good places for heavy crude to go and the differential blew out because Whiting was not taking the heavy in large volumes yet. We had to fire it at one of the other Chicago area refineries, and you had limited outlets. Where, now, you have not only BP Whiting ramping up, especially, but then you have Flanagan South Pipeline. That's our system opening up in the middle of the year, along with the Seaway expansion. And that really ups dramatically the pathway for heavy crude down into the Houston and Port Arthur refining areas. So I think those are what we'd point to, and then Mark has already gone through some of the supply push that we're going to see, including, I should add, the Husky/BP Sunrise sometime in 2014. That's new production coming out of the Oil Sands.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Okay. That's great. And then can you just -- I think you touched on in your comments, but have you gotten through all the cleanup that was required on 6B? I think you had a mandate, if I recall, to be done with a bunch of that by the end of 2013. Did you get done there? Is there additional spending we should expect, and then anything on -- any update on sort of the fines or what now we might be looking for there?

Mark Andrew Maki

Yes, I'll talk about the spending profile, and then Steve can talk about the status of the work. But what we have accrued, again, in the numbers is what we spent historically, plus what we expect to spend in the future in terms of the remaining cleanup that is to be done. There's a base provision for a fine in that number, and wherever ongoing monitoring we're going to have in the future. So when we do that accrual, it's taking into consideration past costs and what we expect future costs to be in. It's always our best estimate as we're sitting here as we make -- complete our financial statements every year. Maybe, Steve, you want to finish up with the status of the cleanup?

Stephen John Wuori

Sure. Well, they were under the EPA order for the last of the areas of what really is light -- very light contamination. There were 3 areas for dredging. We're completed on 2 of those 3, and then the one that held us up was the very last one, the Morrow Lake and the Morrow Lake Delta area dredging. And, really, what caught us there was that we were not able to get approval for a pad site for the dredge equipment and for storing the material that we dredge up. So we're now -- we found another site. There was a public meeting this week with regard to that site, and that should now move along. But I think that's really what happened in the fall of 2013 is that we weren't able to get the approval for the site that we needed, and that's what pushed us then into the winter.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Okay. And then last one for me then is just, again, kind of related to the drop-downs for MEP. Can you just remind us again of how you're thinking about the right multiple to drop it down, that you can now have the stock out trading for a little while? What is the right multiple on EBITDA or whatnot, to drop assets down to MEP?

Mark Andrew Maki

Well, then, certainly that will be the discussion between the special committee of Midcoast at the receiving end and EEP sending it down. But I think a reasonable thing to think about is 8, 9 or 8 to 10. Keeping in mind, Enbridge Energy Partners has a big incentive to -- it can help Midcoast be successful. So we take that kind of range with appropriate consideration.

Operator

Your next question comes from the line of John Edwards with Crédit Suisse.

John Edwards - Crédit Suisse AG, Research Division

Just kind of a follow-up to Mark and Ted's question on the drop-downs. Just if you could give us an idea of the thought process between, say, being at the low end of your targeted range versus the high end of the target ranges. What are the trade-offs there that you're balancing?

Mark Andrew Maki

Mostly, John, I would say it's just what are the capital requirements at EEP, would be the bigger drivers. So for some reason, let's say, our capital program accelerated from what we're talking about here that might drive us to the higher end, or if it's slower than what we have here, it probably will drive us to the lower end. There would be other considerations we might look at. Sizing of -- what's the reasonable amount to drop in the Midcoast, due to what's happening organically there. There's a lot of different things we'll be looking at. But we wanted to give ourselves a little bit of latitude in the range, and -- but those will be a couple of the pylons we'll be looking at.

Operator

Your next question comes from the line of Shneur Gershuni with UBS.

Shneur Z. Gershuni - UBS Investment Bank, Research Division

Most of my questions have been asked and answered. Just 2 quick follow-ups. It sounds like your EBITDA will be somewhat lumpy throughout the year, kind of as projects come online. Given your guidance range that you have, is there a way, or do you have a number in hand that you can sort of give us with respect to kind of like what your Q4 run rate would be? And if you can sort of give us color on what you think your coverage ratio would be kind of in Q4 rather than sort of the average for the year, assuming that it's higher than where it is at the beginning of the year?

Mark Andrew Maki

Maybe a few things on that. I mean, Q4, we expect certainly to be one of the better quarters of the year, and the reason for that is some of the things that Steve touched on. The projects going into service, midpoint of the year, being able to pull more volumes to the system, heavy to the South and I'm going to the later point in the year, light access to the markets in the East. So I think sufficient business drivers there would cause Q4 to be a better end. But one comment on coverage, we tend to have our maintenance lumpy throughout the year, so it's hard to say -- that's why we like to look at things on an annual basis. Some quarters are very light, some quarters are very heavy. So I took the long way of not giving a really good answer to your question, but we would expect, I think, the exit rate to be stronger than, say, entry rate.

Shneur Z. Gershuni - UBS Investment Bank, Research Division

Okay. And just one quick follow-up, and sorry for another question on MEP drop-downs. But it sort of seems kind of like the circular reference of sorts. Essentially, you have MEP looking to grow its distribution kind of at a certain pace. Disappointing results yesterday, it sort of makes that a little bit tougher to do, so then you fall into the category of needing to either accelerate or change the, I guess, the accretion value of a drop-down. Does that change kind of your equity funding needs as you sort of take a look at the whole picture in terms of you were expecting to take in $2.6 billion from MEP drop-downs, is that lower now? I was just wondering if you can sort of discuss that, kind of in context of how you manage all the moving parts together?

Mark Andrew Maki

Yes, a few things. And first off, I mean, recognize that it was 6 or 7 weeks of results, and probably the area in the gas business which tends to be probably the choppiest, which is the winter, given the -- North Dakota they're used to cold weather. Panhandle Texas, not so much so. So do keep that in mind. With respect to the $2.6 billion off the funding chart, whatever -- it's -- there's really no meaningful difference to the values and principles we expect to get out of Midcoast as drop-downs across time. Certainly, I think your notion of a circular reference, it's an interesting one. I like that. We've got a lot of different factors we got to balance as we think about the size of the drop-down. But we touched on pretty good here, and we'll let it go, which is the -- EEP is going to have requirements during the year, plus it has this -- we've got a strong desire to see Midcoast to again be successful. And so those will be, again, key drivers to the size, the amount, and the multiple of the drops.

Operator

Your next question comes from the line of Sharon Lui with Wells Fargo.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Just a question on your Liquids integrity spending. So it looks like you earmarked about $270 million for this year. Can you just remind us how much you spent in 2013 and if the $270 million would be an appropriate number going forward?

Stephen J. Neyland

This is a Steve Neyland. I'll take this, and let Steve Wuori chime in, if he'd like. So the $270 million is fairly consistent with the 2013 number. It fairly, like I said, some of the 2013 number, when you just look at our big program there. When we look forward, we expect those amounts will come down and keep those periods because we've done a lot of work in and around our systems, and not to mention a replacement of a number of our paid co-head lines, 6B, being the one of most prominence. So from that standpoint, we see a trend that would go down in future periods.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. Okay. And I think, in the opening comments, you indicated that you experienced, I guess, some delays in permitting. Do you think that this is just a one-off issue, or could other pipeline projects, in terms of timing, be impacted?

Mark Andrew Maki

Okay. Steve, you want to handle that one, Steve Wuori?

Stephen John Wuori

Sure, Sharon. I guess you're referring to the Line 67 delay or longer than expected to receive the amendments of the presidential permit. That's pretty unique. That's the only one of its type for us in our whole project portfolio. And as you know, the State Department is taking great pains to do everything very carefully, and that's why it seems to be taking longer than we had anticipated for the amendment, which is very simple in the case of Line 67. It's an existing pipe. There's no pipe being laid. There is just horsepower being added to the line to bring its capacity up to -- closer to what a full 36-inch diameter line should carry. So it's a pretty simple amendment. But the State Department is using a very detailed process to go through the assessment of that, and that's why we wanted to -- explain and disclose that we expect it to take longer than we had anticipated. We would have thought that we would get the permit by June of 2014. It doesn't look like that's going to happen, and that's why we've really implemented the other temporary system optimization and utilization measures that Mark talked about in his remarks.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. That's helpful. And then, I guess, Steve, maybe if you could comment on the potential change in rail safety regulations and how that could potentially impact, I guess, takeaway constraints in your operations in the Bakken?

Stephen John Wuori

Sure. Well, that's -- the earlier question was about crude exports and the other big question in 2014 in the crude markets is going to be what, exactly as you asked it, what will the effect be of any rail safety measures or changes in regulation. We're staying very close to that and wanting to understand exactly what direction it's taking in both the U.S. and also in Canada. There's a couple of things. One, it involves, of course, the DOT or DOT-111, cars which are the most predominant types of cars being used for crude oil and how quickly regulations around the new standard for those cars, which involves certain shields and thicker wall and other things, how quickly that's going to be required to change. Certainly, every new car comes with the new design. And then the second question is whether there will be any mandates on the rail systems to routing of crude oil movements away from towns and cities. And it's impossible, right now, to predict what actually will be taken on those fronts or how quickly it will be. We are staying close to it. Of course, our own rail operation is very, very small, relative to what we do mostly, which is move oil by pipe. And so we're just going to have to wait and see. As I said earlier, we are seeing a return to pipe in our nominations coming to the system. Shippers, of course, would have to speak for themselves on what their motivations are in coming back to pipe. It's largely price-driven because, so far, there really hasn't been any constraints put in any significant way, on the rail system. The question is, will there be and each producer, I think, especially, will be positioning themselves for that. But those are the main areas that are under discussion. How quickly should the car fleet be updated and then the question of routing.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And maybe just a comment on potential testing of the product being shipped. Would -- do you think that would fall under the responsibility of a loading and unloading facility like Enbridge is?

Stephen John Wuori

Well, I think, generally, like at Berthold, we -- most of our volumes come in by pipe, some by truck, but mostly by pipe. And our pipeline specs for years have had limits on sulfur density, H2S, hydrogen sulfide, et cetera. So I think, generally, those volumes are already, in a sense, prequalified before they enter the pipeline system. I think there is a debate around exactly what testing protocols there needs to be, especially at rail-loading facilities that never see a pipeline, that would have inlet specifications. There are rail-loading facilities that basically are truck-to-rail without any pipeline involved at all. And I think that's where there may well be changes coming in regulation around the testing, and also determination of which packing group the crude ought to go into, Packing Group 1, Packing Group 2 and so on. But generally speaking, anything that has been in the pipeline system has already been subject to the inlet specifications in the pipeline tariff.

Operator

Your next question comes from the line of TJ Schultz with RBC.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Just one quick thing, I think this was touched on a little bit earlier. But just to clarify on the 2% to 5% distribution growth target, how do we look at that number? Is that a guidance for targeted annual growth, or a longer-term CAGR that you want to hit? So that if distributions were flat for some time, there would be a bigger catch-up to meet, kind of a longer-term, 2% to 5% range, or is that range more of just an annual growth that you want to resume at some point?

Mark Andrew Maki

It's an annual growth target for us, TJ. And that's what we'd like to hit every year and then over time, as we've talked about before. As our projects come into service and more and more of our financing, of course, is behind us, then we'd expect to accelerate to the higher end of that range.

Operator

Ladies and gentlemen, this concludes the time allotted for our question-and-answer session. I would now like to turn the call back over to Mr. Sanjay Lad for closing remarks.

Sanjay Lad

Great. Thank you, Patrick. We appreciate everyone participating in the call this morning. I would like to remind you that I will be available for any follow-up questions you may have after the call. Thank you, and have a great day.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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Source: Enbridge Energy Partners, L.P. Management Discusses Q4 2013 Results - Earnings Call Transcript
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