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Enbridge Energy Partners, LP (NYSE:EEP)

Q4 2012 Earnings Call

February 14, 2013, 10:00 a.m. ET

Executives

Sanjay Lad – Director Investor Relations

Mark Maki – President

Stephen J. Neyland – VP Finance of General Partner

Stephen J. Wuori – EVP Liquids Pipelines & Director General Partner

Terrance L. McGill – President, Director of General Partner

Darren J. Yaworsky – Treasurer

William M. Ramos – Controller

Leon A. Zupan – EVP Gas Pipelines & Director

Analysts

Brian Zarahn – Barclays Capital

Ted Durbin - Goldman Sachs

Sharon Lui – Wells Fargo Securities, LLC

Russell Payne – Wells Fargo

John Edwards – Credit Suisse

Gabe Murray - BAML

James Jampel – HITE

Robert [Inaudible] – Macquarie

Operator

Good day ladies and gentlemen, and welcome to the Q4 2012 Enbridge Energy Partners, LP earnings and 2013 guidance conference call. My name is Tracey, and I will be your operator for today. At this time all participants are in listen only mode. We will conduct a question and answer session towards the end of this conference. (Operator Instructions).

As a reminder, this call is being recorded for replay purposes.

I’d like to turn the call over to Sanjay Lad, Director Investor Relations. Please proceed sir, thank you.

Sanjay Lad 

Thank you, Tracey. Good morning and welcome to the 2012 fourth quarter earnings and 2013 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 releases associated with it can be downloaded from our website at EndbridgePartners.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., Leon Zupan, President Gas Pipeline Endbridge Inc., Terry McGill, Senior Vice President, Operations and Engineering, and Darren Yaworsky, Treasurer.

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 Three.

I’ll now turn the conference call over to Mark Maki , President.

Mark Maki

Thank you, Sanjay, good morning and welcome everybody. Our agenda this morning includes a brief recap of 2012, a review of our fourth quarter results, then we will discuss the partners

Growth [inaudible] in addition presenting our financial guidance for 2013.

Let’s start with a discussion of system integrity. Achieving our long-term financial operational and business targets, requires a focus on safety. Everything starts with safety, and safety is our top priority.

During 2012, we completed one of our most ambitious programs to enhance the integrity of our pipeline systems. Operating investments included inspecting our pipeline systems with the latest proven technology of high resolution inline inspection tools.

The data from these inline tool runs allows us to identify areas for immediate attention, and plan our future operating and capital integrity requirements, while we continue to safely operate each pipeline.

Our activities also included significant pipeline rehabilitation and replacement programs. These types of programs are not new for the partnership. We are committed to achieving industry leadership and pipeline integrity and safety, and we will make the operating and capital investments necessary to achieve this objective.

Turning to system utilization, no other MLP has a liquid pipeline systems with the scale and positioning of our systems. Our location and market access is led to and will continue to lead to further expansion opportunities.

We move a great deal of volume in our liquids pipeline systems, and deliveries were strong throughout the year. As an example, our Lakehead system achieved record deliveries of 1.79 million barrels per day for 2012. Strong system utilization and strong North American crude oil supply fundamentals, support our plans to expand our system.

Supply and market disruptions are a part of the business, and it seemed 2012 had more than usual. As an example, constraints in markets and transportation resulted in higher regional crude oil differentials that contributed to the emergences of rail as an interim competitor for our North Dakota system during the year. We will address our longer-term views on rail later in the presentation.

Turning to secured growth. Our assets linked the largest source of crude oil supply in North America, with the premium markets in North America. And this is like great opportunities for the partnership.

During the year, Enbridge Partnership announced a series of complimentary infrastructure projects to facilitate broad, crude oil market access in North America. The partnership was successful in securing approximately 7.3 billion of attractive growth projects.

These Liquids Expansion projects are underpinned by long-term, low-risk commercial frameworks that will provide us a sustainable and predictable stream of cash flow to our partnership and our unit holders.

Moving to the area of project execution, we are progressing very well on our announced growth projects, and are well positioned to deliver this projects on time and on-budget. This quarter, our Line5 expansion and the Bakken pipeline expansion will come into service.

Turning to commodity prices. Declines in natural gas and natural gas liquids prices, or NGL provided substantial headwinds for our natural gas business segment during the year. Declines in NGL prices were the primary reason for under performance in the partnership in 2012. These headwinds are expected to persist for the near-term and likely throughout 2013.

Now this said, our natural gas assets are well positioned to grow, as natural gas and NGL prices recover.

Please turn to slide 4, and I’ll turn the call over to Steve to discuss our financial results.

Steve Neyland

Thank you, Mark. Fourth quarter adjusted net income of 87.2 million was 29.2 million lower than the same period in 2011. And full-year adjusted earnings were 54.4 million lower than in 2011.

Full-year adjusted EBITDA of 1.14 billion came in at the mid-point of our revised 2012 EBITDA guidance. The quarter was unfavorably impacted by low natural gas liquids prices and increased operating and administrative expenses.

As noted in Mark’s opening comments, declines in natural gas and NGL prices created headwinds for our natural gas business unit during the year. Adjusted results are provided to more clearly focus on our underlying business performance.

The main items eliminated from adjusted results are, additional environmental cost, which are net of insurance recoveries associated with the incidence of Line 14 and 6B, unrealized non-cash mark-to-market, net gains and losses, and other items noted in our supplemental slides.

Adjusted earnings per unit for the fourth quarter was $0.18 compared to $0.32 for the same period of 2011. Lower adjusted earnings coupled with the increase weighted average number of units outstanding in 2012, compared to the fourth quarter in 2011, resulted in lower year-over-year earnings per unit.

Our as-declared distribution coverage ratio on a year-to-date basis was .79 times. I’ll provide more detail on distribution coverage in a few moments.

Please turn to slide 5. For our Liquids Segment, adjusted operating income of 133 million for the fourth quarter was 28.5 million lower and 17.6% lower than the same period from 2011. Fourth quarter 2012 adjusted operating revenue remained flat when compared to the same period in 2011.

Operating revenue increases due to higher indexed transportation rates on our systems, as well as increased revenues associated with our Cushing storage facilities were offset by lower volumes transported on our systems during the quarter.

Operating and administrative expenses increased due to higher pipeline integrity expenses, an increase in regional property taxes and workforce additions. Additionally, fourth quarter 2012 results included approximately 9 million of unusual cost related to the remediation of crude oil releases, primarily around our terminals.

Volumes on our Lakehead system were strong at 1.74 million barrels per day during the fourth quarter. The trend in Lakehead volumes during the third and fourth quarters was primarily due to significant scheduled and unscheduled upstream and refinery maintenance activities.

Volumes on our North Dakota system declined 16% in the fourth quarter versus the third quarter, due to the emergence of rail as competition to our North Dakota system. We will touch on this in a moment.

During the quarter, we increased our total estimated – estimate related to the Line60 incident by 10 million to 820 million to reflect revised monitoring and restoration efforts. The accumulative amount collected from our insurance recoveries is currently 505 million, and we expect to recover the balance of our aggregate liability insurance coverage of 145 million from our insurance providers in future periods.

Through the end of 2012, we have spent approximately 704 million on Line 6B remediation and had an estimated liability remaining of 116 million. Please turn to slide 6.

Adjusted operating income of 42.9 million for the fourth quarter was 8.5 million lower than the same period in 2011. The decrease in fourth quarter, natural gas adjusted operating income over prior year was primarily due to lower NGL prices, lower volumes from our assets position and dry gas producing regions, and higher operating and administrative cost.

Higher operating and administrative expenses were the result of higher workforce related cost, and pipeline integrity cost. Natural gas volumes on our East Texas system were lower than the previous year, due to a continued decrease in drilling in the region, as a result of the weak natural gas price environment.

Volumes on our Anadarko system remain strong as producers continue to pursue rich gas in the area. Please turn to slide 7.

The chart on the left shows our full-year distributable cash flow of 603.7 million, full-year distribution coverage on an as-declared basis was .79 times. The calculation includes the amounts declared for the fourth quarter, and includes i-unit, Paid-in-Kind distributions, as though they were paid in cash.

As expected, our distribution coverage is below one time, due to the financing of our significant capital program. These commercially secured growth projects will begin entering service in 2013, and ramp up in the future periods.

At the end of the year, we had approximately 1.5 billion of available liquidity. We recently increased our bank facilities by 425 million earlier this month, which boost our current available liquidity to approximately 2 billion. The partnership now has an excess of 3 billion of credit facility capacity, to provide enhanced financing flexibility.

For further details on our financial results for the quarter, I encourage you to review our supplemental slides that are posted on our website. Please turn to slide 8, and I’ll turn it back over to Mark to provide an update on the partnerships business outlook.

Mark Maki

Thank you, Steve. I want to talk a little bit about the liquids market access initiatives and how the programs we have underway begin to address some of the price dislocations that we’re seeing in North America.

So as you can see from the map on the left side of the chart, the market continues to experience price dislocations for crude oil between Inland sources and the Waterborne equivalent. North American supply is priced at a discount to import Brent, Maya or similar barrels due to current infrastructure constraints, and supply and demand imbalances.

Without market access, [inaudible] will to experience sustained price discounts and refineries are vulnerable to world crude oil pricing. The market access programs announces by Enbridge and the partnership are part of the strategic initiatives, we’ve collectively untaken to unlock the best markets along the U.S. Gulf Coast, the U.S. East Coast, the U.S. mid-west, and Eastern Canada, to match growing North American supply to markets that have traditionally been served by foreign offshore imports.

As it relates to the current take away environment in the Bakken, volume growth in the Bakken has quickly filled the declining [inaudible] needs of lateral needs of mid-con and refiners, and overwhelmed available outbound pipeline capacity and markets.

Rail transportation is helping to address immediate needs of crude oil produces in the oil shale regions, to bypass constraints. It is our view within the longer-term, as pipeline expansion projects are completed, new light crude oil consuming markets are open, that at that point, real volumes will then be supplying markets that cannot be economically accessed by pipelines, such as the U.S. West Coast.

As depicted on the map on the right side of the chart, once Enbridge and the partnerships current market access programs are completed, during the 2016 time horizon, we believe the current environment of historically wide crude oil differentials will be alleviated, as we will be able to deliver substantial incremental volumes of crude oil to new markets.

The cost to access those markets by pipe, if the infrastructure were available, will be less than $10 per barrel.

The strength of the Enbridge plan is the diversity of premium markets that our pipeline system is ideally positioned to access. And let me describe the strategies and the projects that unpin our plan, and we’ve announced so far. So with that, let’s turn to slide number 9.

Over the past year, Enbridge and the partnership have announced a series of liquids expansion programs to access new markets in North America. Our projects result from the unprecedented expected growth in North America crude oil production, in the Canadian Oil Sands and the Bakken.

We have summarized on slide 9 the various projects that comprise our U.S. Gulf Coast strategy and our light oil market access initiative. Now there’s a lot of detail in this chart, so what I’m going to do is focus high level on the strategy and how these projects collectively address the transportation needs in North America.

Enbridge Inc. has made great progress in establishing a new and much needed corridor to the U.S. Gulf Coast refinery market by acquiring, reversing the flow, and expanding the Seaway pipeline in a joint venture with Enterprise Products.

Additionally, construction is underway on both the Flanagan South and Seaway pipeline expansion projects that will provide capacity to deliver 850,000 barrels a day, to the largest refinery complex in North America, specifically the U.S. Gulf Coast.

The partnership has multiple complementary upstream expansions of its Lakehead system under way. For example, we are expanding both Line 67 into Superior, Wisconsin, and Line 61 into Flanagan, Illinois to their full hydrologic capacity of 800,000 and 1.2 million barrels per day respectively.

These expansions involve construction of new pump stations on existing large diameter pipelines that were installed a number of years ago.

There are other projects that are also key to the strategy detailed on the slide. What this strategy does is match heavy crude oil from Canada, with refineries already capable of handling heavy oil.

As it relates to light oil, let’s start in the Bakken. Our light oil market access program responds to significant recent developments, we expect a supply of light oil in the Bakken area, and western Canada, as well as refinery demand for light oil the U.S. Mid-west and Eastern Canada.

Supply from North America areas is very attractive to refineries in the U.S. Mid-west and Eastern Canada compared to more costly offshore sources. As part of the light oil market access program, the partnership announced the Sandpiper Project, which will establish a new high volume export pipeline out of the Bakken region, by expanding the partnerships North Dakota mainline system.

The takeaway capacity of the partnerships North Dakota system will be expanded by 225,000 barrels a day, to a total of 580,000 barrels per day, with a target in service date of early 2016.

Ultimately, our expand in North Dakota system will continue to provide a safe, reliable, and long-term pipeline take away solution for our customers, and will enhance their net backs.

The light oil market access and Eastern access programs complement each other since the Eastern markets are a natural outlet for growing light crude oil supply from Western Canada and the Bakken, as many of the refinery centers in the region consume light crude oil.

At the same time, we’ve seen refinery capacity conversions to accommodate a heavy feed stock in the U.S. Mid-west. [inaudible] access to Eastern markets, the partnership is first expanding its Line 5 from Superior, Wisconsin to Sarnia, Ontario. Second, expanding the Spearhead North pipeline into Chicago, and third, replacing Line 6B, which will increase the pipelines capacity into Sarnia, Ontario.

Please proceed to slide 10. The partnerships Liquids Expansion projects are underpinned by long-term low-risk commercial frameworks that will provide sustainable and predictable stream of cash flows to the partnership and our unit holders. These investments are underpinned by cost-of-service or ship-or pay basis commercial structures, that control elements of throughput and capital of cost risk.

As depicted in the chart, collectively these crude oil projects are transformative, and they will progressively shift the partnership to an even lower-risk business model. The bottom line is that long-term, the low-risk commercial underpinnings of these accretive growth projects provide us a high level of confidence in our distributable cash flow growth.

Let’s move forward to slide 11, turn the call back to Steve, to talk about our 2013 guidance.

Steve Neyland

Thank you, Mark. For 2013, we estimate the partnerships adjusted EBITDA will increase an access of 10%, and we will be between 1.25 and 1.35 billion. Operating income is estimated to be between 860 million and 940 million, with approximately 80% contribution from our liquids business, and 20% from our natural gas business.

We expect appreciation will be between 390 and 410 million. We have a number of growth projects that will begin service throughout the year. As these projects ramp up and begin delivering cash flow to partnerships EBITDA growth trend will accelerate, as depicted in the chart at the bottom right of the slide.

We continue to target distribution growth at an annual growth rate of 2 to 5%.

Moving on to slide 12, here we present our volume forecast for our liquids and natural gas businesses that was used to develop our forecast for 2013. We expect total liquids pipeline system volumes to increase in 2012, with continued production growth out of Western Canada, complimented by increased downstream demand. We anticipate strong system utilization, with average deliveries of approximately 2 million barrels per day on our Lakehead system. Lakehead volumes will continue to increase over the course of the year as Western Canadian production volumes increase.

As it relates to our North Dakota system, our Bakken pipeline expansion will introduce an incremental 120,000 of take away, out of the region, over the next month. With the combined ship-or-pay volumes on the Bakken pipeline expansion, and our existing North Dakota pipeline, we forecast that our North Dakota volumes, for which we receive revenue, will decrease the year-over-year to 190,000 barrels per day.

As noted by Mark, rail transportation has also emerged an alternative method of shipping crude oil to key markets due to the lead-time required to get our new pipelines into service. Transportation and market access constraints have resulted in large crude oil price differentials between the North Dakota supply basin, and to key light oil refining market centers.

With the current environment of high regional crude oil price dislocations, rail has become a stronger competitor to our North Dakota system, and is expected to decrease our system utilization over the short-term.

We believe the North Dakota system volumes will improve in later periods, as future pipeline expansions and enhanced market access to Eastern Canada markets and Eastern [inaudible] markets are expected to decrease current crude oil price differentials.

Overall volumes in our natural gas business are forecasted to remain steady through 2013. Volumes in our Anadarko system are expected to increase in 2013. This volume growth will be facilitated by the addition of the 150 million cubic feet per day of capacity from the Ajax processing plant, which will enter service in the middle of 2013.

The operating income contribution from our Anadarko system represents more than half of the natural gas segment in 2013. We expect volumes in East Texas will decrease approximately 10%, due to the moderate level of drilling activity for dry gas and the forecasted natural gas price environment.

Volumes in North Texas are expected to remain flat in 2013.

Our supplemental slide deck provides some details of our forecasted 2013 commodity positions, hedge levels and commodity price sensitivities. Since our natural gas commodity position is relativity flat, we have minimal commodity exposure as it relates to movements in the price of natural gas, and are more exposed to fluctuations of the price of natural gas liquids with our long NGL position. Approximately 70% of our forecast in commodity cash flows for 2013 are hedged.

Please turn to slide 13. The partnership was successful in securing approximately 7.5 billion of attractive low-risk growth projects in 2012. This slide provides our 2013 capital expenditure forecast, which is estimated to be 2.28 billion, and is inclusive of approximately $130 million in core maintenance.

Please turn to slide 14. The partnerships net capital expenditures forecast through 2016 is presented in the chart. In addition to the nearly 2.3 billion of forecasted capital expenditures for 2013, we are forecasting an average annual net capital spend of approximately 1.7 billion. The capital spend profile remains relatively consistent from previous disclosures.

From a financing perspective, the partnership will benefit as projects begin to [inaudible] service beginning 2013 until 2016. The increasing distributable cash flow will enhance our distribution coverage and credit metrics.

The eastern access and mainline expansion joint fund agreements with our general partner, Enbridge Inc., enhance the partnerships financing flexibility. The partnership holds an option to reduce its funding requirements by over 700 million. This option expires on June 30, of this year.

We will plan to fund our capital program with 50% debt and 50% equity, along with the over 3 billion of credit facilities, we are well positioned to execute on our financing plan for 2013, and maintain our investment grade credit rating.

Moving forward to slide 15, the graph provides perspective as to high these previously discussed secured projects will improve our distribution coverage, and enable the partnership to achieve this distribution growth target.

With our large capital program, current year distribution coverage is expected to be below 1 times. Softer coverage is inherent to prefunding equity capital, and our track record demonstrates our commitment and financial discipline to manage through these robust expansion periods, as we did in 2008 and 2009.

The green part of the bar represents potential range of coverage outcomes in 2013, depending upon various economic and operational factors.

The partnership continues to target long-term distribution coverage of 1.05 to 1.1 times. The long-term low-risk commercial underpinnings of these accretive growth projects, provide us with a high level of confidence in achieving this improvement to our distributable cash flow.

Please turn to slide 16. I will now turn it back over to Mark, to address the key takeaways.

Mark Maki

Thank you, Steve. Just a very brief wrap-up and then we’ll go to Q&A. The long-term outlook for the partnership remains very strong. We selectively secured over $8 billion of growth capital since 2012, as projects are proceeding on schedule, and will progressively [inaudible] from the partnership towards a lower-risk business model. With basically cash flow is being secured predormitally by long-term low-risk commercial framework such as the cost-of-service for demand-based contract structures.

The partnerships distributable cash flow growth will begin to accelerate once these accretive growth projects enter service, which will [inaudible] a long-term distribution growth outlook.

I think with that, Tracey, we’d like to open the lines for Q&A.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Thank you, your first question comes from the line of Brian Zarahn from Barclays. Please proceed.

Brian Zarahn – Barclays Capital

Hi, it's Brian Zarahn.

Mark Maki

Hey, Brian.

Brian Zarahn – Barclays Capital

Steve is on the line, so can you give a little more worry on how rail is becoming a bigger competitor to your pipe system for your crude volume? Does that have any impact on Sandpiper?

Stephen J. Neyland

Sure Brian, it's Steve. Certainly in 2012, we saw a real surge in rail movements especially out of North Dakota, somewhat out of Saskatchewan in Canada also, but mostly out of North Dakota. And the math I think that underlies that is pretty simple where basically you have a price that is constrained by pipeline market access at the moment. And if you can get to tide water on rail being St. James, or Philadelphia, or Eastern Canada, or the West Coast, you can pay anywhere from $12 to $17 a barrel on the rail and still have a better net back than on pipe. And so that's why we've seen that in 2012. And we expect that to continue in 2013.

The key will be two things. One will be first and foremost more market access by pipe. And that's something that Enbridge Inc. as Mark and Steve have noted is working very hard on in a whole bunch of different directions. And there will be more of that coming. So that's an important piece looking at getting pipe to the markets that are currently attractive to rail, which are tide water markets because pipe will win every time.

The second thing then is more export capacity out of North Dakota. And that's where Sandpiper comes in. And so Sandpiper really is a fit to the new market access initiatives downstream where it will give the supply into the mainline system to pull through into those markets. And so that's why we continue to work on Sandpiper.

Brian Zarahn – Barclays Capital

And so you expect the differentials eventually to narrow over time, but it's hard to predict how long it will take?

Steven J. Neyland

Actually, it isn't that hard, Brian I don’t think. The market is reasonably efficient. And it specializes in closing big arbitrage opportunities. And so as you see now, nearly 400,000 barrels a day of largely Bakken crude moving into the St. James market around New Orleans' eastern gulf refining market.

And capability in Philadelphia at least by way of plans of various companies to supply 800,000 barrels a day out of the 1.3 or 1.4 million barrels a day of refining capacity, invariably, that access is going to create its own leather in terms of the differentials falling and closing in. And that's where it's important that pipe reach the markets where pipe can reasonably and economically do it because pipe can live on a far lower sustaining differential than rail can.

So the wild differentials that are so attractive today particularly out of the Bakken by rail will inevitably close due to greater supply into those markets. And quite honestly, I think eventually Brent has to fall if you think about the equation where U.S. demand is falling, U.S and Canadian supply is rising. That is going to back out a lot of imports that are going to have to go to other markets and will eventually pinch Brent.

So a number of factors moving around the differentials. But there's no question that in the coming couple of years, those differentials are going to close.

Brian Zarahn – Barclays Capital

I appreciate the color, Steve. On your expansion CapEx, you have about $500 million of other projects in your liquids and gas segments. Can you talk maybe broadly about what those projects are? Are those potentially discretionary and could be pushed out until later years?

Mark Maki

We'll take that with Steve Neyland here.

Steven J. Neyland

Yeah, hey, Brian, it's Steve.

Yeah, so there's a combination of items in that remainder inclusive of well-connect capital that we have on our gas business inclusive of various things such as compressor work, our additional compression that we might put in on our gas business, or pump stations for that matter on our liquid side just to enhance current earnings that we have. So it's actually fairly typical. And the number seems big. We stretch it out over that long timeframe. It's fairly typical remainder of capital that we haven't specifically called out in our slides.

Brian Zarahn – Barclays Capital

Thank you.

Operator

Thank you, your next question comes from Ted Durbin from Goldman Sachs. Please go ahead.

Ted Durbin – Goldman Sachs

Thank you. Understood the impact from rail, but I'm trying to understand a little bit better on Lakehead. We've had these sequential declines on the volumes there pretty much every quarter throughout 2012. And you're forecasting it to pick up again to about two million barrels a day in 2013. Can you just talk about how you see the market shifting to where you'll reverse that decline off the Lakehead as we go forward?

Mark Maki

Steve Wuori, it's Mark. Can you handle that one please?

Steve Wuori

Sure, hi, Ted.

There's a number of factors that I would point to. First of all in 2012, we had of course expected that the Imperial Exxon Kearl Lake new mining and development project in the oil sands would turn on in the early fourth quarter, which it did not do. And that could be coming on very shortly here. I think they're pointing to weeks rather than months right now in terms of that startup. And that's 145,000 barrels a day roughly of blended throughput. Not all of that may necessarily hit the Enbridge Lakehead system, but most of it should. So there's the supply delays that we've seen, supply growth delays that we've seen.

We also have had restrictions on our own system, certain pressure restrictions on certain lines that we've talked about as we complete the integrity maintenance program on those lines. And also congestion in some of our terminals, which effectively reduces the available capacity of the pipes as we have congestion in the terminals among all the various types of crudes that we move through.

And then also in 2012, there's been some big turnaround activity like Marathon at Detroit turning its refinery around to take more heavy crude. That took a chunk off of 2012's throughputs. And BP at Whiting with that huge turnaround that they're doing with that refinery conversion is coming up. But we've got that kind of accounted for in terms of where that crude is going to go.

And then as the mid-year approaches and we look beyond mid-year and the lighting conversion, then we see just the very strong picture for refineries that are now tooled for greater heavy crude, more supply coming from upstream. And then as we go along through the year, certain restrictions on our system will get removed also.

I think those would be the circle of reasons that we're guiding the way we are on volumes.

Ted Durbin – Goldman Sachs

That's very helpful, Steve. And so it sounds like you're expecting a lot more heavy barrels versus light if you think about the forecast? Or how does the mix shift this year, this coming year?

Steven J. Wuori

I think we certainly see some heavy growth. There is continuing light growth though in the Alberta Cardium play and other light oil plays. And that's actually been surprising to the upside. As that gets its' feet under it, it's being drilled very aggressively just like the Bakken is. And so we're also seeing some light crude growth. Our light crude system has not been in apportionment and has had the ability to move that and I think it will. So we're seeing a mixture of both I think, both light and heavy supply rising.

Ted Durbin – Goldman Sachs

That's great. And then on the [inaudible] business here, I'm just wondering if you can talk about how much ethane rejection you're seeing sort of across the system now, how much that's sort of the pullback in the rig count here is impacting the volumes there certainly as people pull back away from some of the ethane heavy wells.

Mark Maki

It's Mark. On the ethane rejection, we are seeing ethane rejection across a lot of our processing fleet in the mid-continent and North Texas. And roughly 10% of our NGL volumes are down. I you look at our overall aggregate productions, about 10% off from what it was say in third quarter.

And with respect to drilling activity, really it's been very steady across North Texas and the Panhandle area driven by [inaudible]. And what we are seeing is even though as we lose dry gas volumes, we're picking up richer gas as kind of a substitute. Liquids for us frankly is better. And so that's probably one thing I guess I'd watch.

The volume may slip some or stay sideways. But if we're replacing dry gas with rich gas, that's a pretty good tradeoff for us.

Ted Durbin – Goldman Sachs

Got it, okay, that's it for me. Thanks, guys.

Operator

Thank you, your next question comes from the line of Sharon Lui from Wells Fargo. Please proceed.

Sharon Lui – Wells Fargo Securities, LLC

Good morning. Just a couple of follow-ups. So for your 2013 guidance, are you also assuming that ethane rejection continues?

Mark Maki

Sharon, it's Mark again.

Yes, through either all of '13 or pretty much all of '13 is our assumption.

Sharon Lui – Wells Fargo Securities, LLC

Okay, and then just looking at your guidance for the North Dakota volumes for the Bay system, it looks like it's a pretty dramatic decline of about 40%. Is that all from rail or is there something else?

Mark Maki

Basically, all rail, Sharon, is the assumption that we're making there. And then as Steve commented I think very well, we do see that remedying in due course as open up access to new markets. And ultimately, the installation of Sandpiper a little bit further out in our planning horizon.

Sharon Lui – Wells Fargo Securities, LLC

Okay, and then I guess in terms of maintaining the great credit rating and your debt metrics, which was close to five times, what are your thoughts in terms of exercising that option to perhaps fund a smaller interest in some of the projects?

Mark Maki

It's Mark again, Sharon. That option expires in June. Certainly, we're going to look at what our capital needs are, capital raising activities, and consider that. It's something that will give a lot of consideration to over the next couple of quarters as we come up on that June 30 timeline.

But as far as feeling an immediate pressure to do it or make that decision today, that isn't there.

Sharon Lui – Wells Fargo Securities, LLC

Okay, and you still remain comfortable I guess delivering the low end of your distribution growth guidance for '13?

Mark Maki

We are still targeting that 2% to 5% growth. And certainly every distribution increase decision is one that we review of course with our board of directors. But that's their objective for a number of years. We have not changed that objective. And we're going to work very hard to achieve that objective.

Sharon Lui – Wells Fargo Securities, LLC

Okay, great, thank you.

Operator

Thank you, and the next question comes from the line of Russ Payne from Wells Fargo. Please go ahead.

Russell Payne – Wells Fargo

How you doing, guys.

Mark Maki

We're doing all right.

Russell Payne – Wells Fargo

I guess my question is on your CapEx budget. The $285 million for liquids integrity, is that included in your cleanup costs that you had gone over earlier? Or that is in addition to? And is there any kind of revenue recapture for those kind of expenditures?

Stephen J. Neyland

Hey Russ, this is Steve Neyland.

Yes, so as it relates to the $285 on slide 13, those costs do not relate to the 6E Marshall incident. These relate to effectively our high bond integrity program, the capital around it. So as we run our inline inspection tools through the pipe, we'll come in and then remediate those sections by either replacing them or sleeving those lines. So that's what the capital represents.

And then as far as recovery, it's a mix of how we receive recovery on that. Some of that we receive as additions to our FSM surcharge. And then some of it, we receive through our index tolling, our PPI Plus. And that's how we receive our payment for that. So it's kind of a mixed bag of how recovery occurs.

Russell Payne – Wells Fargo

So you actually do get recovery on most of that? Is that fair to say, but it takes time?

Stephen J. Neyland

Yeah, so from an economic standpoint, the recovery dollars are better for the partnership if it's under the FSM surcharge versus the index. It's a mixed bag between those two. And for us, it's a discussion that we enter into really on an annual basis with our shippers.

Mark Maki

And to be clear Russ, on the FSM, what that is the utility style cost of service sort of calculation. So think of it like rate base, Russ, is the way to think about it.

Russell Payne – Wells Fargo

Okay, and out of that $285, how much would be under that classification do you think percentage wise?

Stephen J. Neyland

We haven't historically given a hard number as we have to enter into conversations with our shippers. But it's probably – we would probably think about it as a half and half type of situation.

Russell Payne – Wells Fargo

Okay, and is this a number that we can probably – are we going to see something similar to this number next year do you think?

Stephen J. Neyland

Yes, so we're in the process of putting together our long range planning. And that is something that we hope to give more visibility to. But we've done a lot of work certainly in 2011 and 2012. And just on a general trend, we would expect that number as you move into future periods to be lower. And that's a product of all the extra work that's gone on from an integrity standpoint on the liquids and our gas business for that matter over the last two years.

Stephan J. Wuori

Yeah, it's Steve Wuori, Russ. I'd just agree with that and say that for one thing, line 6B will be brand new as of late this year, early next year.

And then the massive work that we've done since 2010 on the system, really I think we'll start to see an inflection point where those costs head down.

Russell Payne – Wells Fargo

Okay, and then just one final question just for reference. I mean what was that number in '10 and '11 for liquids and integrity?

Stephen J. Neyland

'10 and '11, if you look at that same liquids integrity line, I think we're probably right around $200 to $300 million if you were to look back historically.

Russell Payne – Wells Fargo

Okay, for both of those years, '10 and '11?

Stephen J. Neyland

Yeah, I don’t have the number. I don’t have the hard number at my fingertips, Russ, for that one. But it's in that range.

Russell Payne – Wells Fargo

Okay, all right, thanks, guys. That's it for me.

Stephen J. Neyland

Thank you.

Operator

Thank you, your next question comes from the line of John Edwards from Credit Suisse. Please go ahead.

John Edwards – Credit Suisse

Yeah, good morning, everybody.

Mark Maki

Good morning, John.

John Edwards – Credit Suisse

Just to be clear, let's see, I think it's on slide 14 I guess it is, so the capital forecast, that is net to Enbridge Energy Partners' net of the shared funding arrangement with EMB, is that correct?

Stephen J. Neyland

That is correct.

John Edwards – Credit Suisse

Okay, so we're looking through 2016 in round numbers I guess doing the math around $7.5 billion. Is that about right?

Stephen J. Neyland

Yes.

John Edwards – Credit Suisse

Okay, all right, and then you mentioned in the release last night and you made a brief comment regarding that on the impact of some of the numbers on both the liquids and the gas side was rising labor costs. And was that more the result of adding more people? Or are you starting to see increases in – are you seeing inflation in labor costs I guess?

Stephen J. Neyland

Yeah, hey John, it's Steve Neyland. It's predominately due to adding more people really around what we call our ORM program and our pursuit of the highest level of integrity and safety for the company. We've added additional resources in order to ramp those efforts.

Additionally, there's some assets that are coming into service such as the Ajax processing plant in line five and others, there's a smaller nature. But predominately, I'd say it's a focus around our ORM activities.

John Edwards – Credit Suisse

Okay, and then because you were sighting that as the reason why the particularly the liquids numbers came down this quarter. I'm just wondering about what impact is that program, the labor program having on the EBITDA numbers for this year. I mean if you hadn't had to add those more people, would you be say $100 million higher in EBITDA, I mean $50 million? What's your thought there?

Stephen J. Neyland

Yeah, that's a hard number to put a finger on. But as it relates to that change in our O&M, our operating expense numbers – you know John, I think I'm going to stay away from giving you a hard number associated with that given that our forecasting for personnel is in process as it relates to future periods. But it does have an impact. A component of what you see there will be part of our expense profile as we move forward into future periods as mentioned.

John Edwards – Credit Suisse

Okay, then let me ask it this way. Then seeing I guess most of your projects, you had a slide where it's cost to service type recovery. So that's certainly rising. But you do have a component that's fee based. Is it fair to say that because it's safety integrity related, you'll be able to recover? I guess what percentage of those costs are you going to be able to recover through your tariffs?

Mark Maki

To the extent the headcount – this is Mark – would relate to a specific project, the headcount would be assigned to that specific project. As an example, this is looking forward as opposed to backwards at the numbers, but if we had added additional people for say the Alberta Clipper project, some of these Asian historical for example, those people would have been effectively added into the cost of service.

And so looking back at 2012, I think it's a little harder to say that the headcount that was added was really tied to any particular expansion project. It is more as Steve alluded to the integrity and safety programs and related activities that the company had underway.

But headcount, we don’t have right at our fingertips, that would be one way I guess of trying to ballpark a number. But that would be one way for us to do it. And then we would take offline with you.

Stephen J. Neyland

Yeah, and then I'll go ahead and quote an approximate number on that John. As we think about our Q4 of '12 over Q4 of '11, we're talking about there's a $28 million change in that OpEx. We noted there was some unusual lead costs around a couple of our terminals for nine. And the other big one is around $8 million when you look this year versus last year. I mean, that just kind of gives you a frame of reference up to magnitude.

John Edwards – Credit Suisse

Okay, and just, sorry to keep focusing on this. I just – what I’m trying to get a handle on is there’s no change to the – you had, in the past, alluded to the fact that after these projects go online you thought your distribution growth should trend towards the higher end of your range. Is that still your thought process? This is because you’ll be able to recover the bulk of these costs and rates, you’re still looking at the higher end of the range when these projects are in service? Is that still a fair statement?

Stephen J. Neyland

We go through a process every year of updating our long-range plan and books and so forth. I certainly believe that to be the case, that we looked at these projects and we announced them and reviewed them with the analyst community that we definitely saw that that was being the trend and that would be the expectation we have when we go through and update this year’s plan, that you’re going to see us, as we get to the end of our planning horizon and these projects come on and the cash flows begin to come to the bottom line, that we’re going to trend to the higher end of that 2 to 5% range.

John Edwards – Credit Suisse

Okay, great. Thank you very much.

Operator

Thank you. The next question comes from the line of Gabe Murray from BAML. Please go ahead.

Gabe Murray - BAML

Hey, good morning, everyone. Two quick ones for me. I don’t know if was asked on previous calls, it seems like you always get asked about it on previous calls, but recently you had an NLP hit the market with a substantial amount of this long-term senior note issuance, which gets, I guess, hybrid equity treatment from rating agencies. I was just wondering if that’s potentially part of the financing base that you guys are looking at?

Mark Maki

Darren, can you field that one?

Darren Yaworsky

Sure. There’s a number of financing alternative that we’re looking at and those are one of them. It hasn’t reached a point where we’d be looking at executing on that at all though.

Gabe Murray - BAML

Okay. Can I ask why not just given what seems to be a pretty reasonable cost to capital relative to your current equity unit cost capital?

Darren Yaworsky

Sure, there’s a bifurcation in the treatment by the rating agencies. As you’re probably aware, S&P gives 50% equity credit and Moody’s provides 25% equity credit. So once you factor that in, it isn’t as cost effective on the surface. So I think we’re still evaluating, monitoring that as that market moves forward and matures a bit more.

Gabe Murray - BAML

Okay, got it. And then second question for me in terms of - and I’m sorry to be on the North – the North Dakota competitive dynamic, is it something where you’re able to attract more volumes if you’re discounting your tariffs on that pipe? Is that something that’s feasible? And I guess in terms of embedded in your EBITDA guidance for the liquid segments next year, is there any tariffs discounting embedded in there?

Mark Maki

This is Mark. There is no tariff discounting embedded in our guidance for next year and then as far as discounting toll having any meaningful affect, I’d defer to Steve. But I think probably the answer is no.

Stephen Neyland

Yeah, I think there, Gabe, it’s really dimes versus dollars and so right now the dollars are available if one has a rail capability, the dollars are available by getting to a tide water market and a toll discount, you know, would not have too much influence on that. So you know, that’s why it’s much more important that we work on the things that will change the dynamic around those huge differentials which are largely market access projects to match up the production growth to the markets where the pricing is best.

Gabe Murray - BAML

Got it. Appreciate the color. Thanks very much.

Operator

Thank you. The next question comes from the line of James Jampel from HITE. Please go ahead.

James Jampel – HITE

Thanks for taking the question. Just two quick questions. Again, back on North Dakota, the volume that was lost to rail, where was that volume headed when you guys had it?

Mark Maki

Well, that volume was largely heading into markets that it could access, that being Minneapolis, Chicago, Eastern Canada and so on. And that’s where the volume will return to when there’s more market access or more capacity. Remember that one of the items on the slide 9, and by the way, slide 9, if you’re going to take anything home as a Valentine’s Day gift, make it slide 9. That is just a tremendous pull together of every, you know, project that’s active. But one of them is the Line Five expansion, which is coming into service very quickly and that is going to draw more volumes out of North Dakota on pipe as we access new capacity into the Eastern Canada market. So it’s things like that that are going to change that and what happened was that the compelling differentials available in St. James and other places on Tidewater really coupled with growing rail capabilities by way of loading in North Dakota and unloading at those Tidewater markets. That’s really what has caused the volumes to move over to rail.

James Jampel – HITE

Okay. And then so I understand the financing correctly, you have about 2.3 billion in capital needs this year. I take half of that being equity at 1.15 and about 700 could come from the option with Enbridge, Inc. is that right, of the 1.15?

Steve Neyland

Yeah, so you’re correct. There’s – the 2.3 is the total as far as if you’re trying to backend equity issuances, you know, to estimate your distributable cash flow, so say with the year and back that out, so we’ll have some cash, but there will be needs for equity and debt for the Partnership in the coming periods. That option that we hold for the 700 million, we’ll hold tight on that here in the near term and see what we want to do with it as we progress into the second quarter. You’re correct, it’s better than $700 million.

James Jampel – HITE

Are you still considering a private placement and/or using EEQ units?

Mark Maki

[Inaudible], do you want to field that please?

Unidentified Company Representative

Sure. I don’t want to sound like a broken record, but we’re exploring all options and EEQ is a unique vehicle that we have that we continue to explore the options on. Private placements, again, is something that is an interesting concept, but the economics need to make sense and the investment type has to be mutually beneficial to both us and to the investor. But we are exploring, as I said, all options available to us.

James Jampel – HITE

Okay, thank you.

Operator

Thank you. The next question comes from the line of Robert [Inaudible] from Macquarie. Please go ahead.

Robert [Inaudible] – Macquarie

Hi. Thanks for taking the question. I know it’s not your planning horizon, but maybe you can comment on how the Enbridge System is competitively placed to deal with some of the competitive options that are developing, in particular, I wondered if you can comment on Enbridge versus the potential partial conversion of the TransCanada Mainline. I know it’s still quite a few years out but at this point they’re talking about something in the upper half of 500 to a million barrels a day. Can you just comment on how, you know, you plan to compete with that system?

Mark Maki

Well, I know Steve Wuori is dying to answer this question, so Steve, can you take that one?

Steve Wuori

Yeah, well, it might be s small exaggeration, Mark, but sure, actually I think you hit on it, Robert, when you said it’s still quite a few years out. And that’s – I think, you know, clear. For example, on our Northern Gateway project, we applied about just under three years ago now and expect to receive regulatory approval next year. So it’s about four years of regulatory in the case of a project of that nature. So what we’re doing in the meantime is much more immediate and that’s line nine, which is the line that has been running from Montreal west to Western Ontario, that line is being reversed by the middle of next year to supply the Quebec refineries of which there are two and that’s a very important piece in this whole question of where crude needs to go and what refiners are basically paying Brent as opposed to getting access to a less expensive western feedstock from either Western Canada or North Dakota. So I think we’re positioned very well in regards to that.

And then the second thing would be our continual efforts into the Gulf Coast with the – with the Flanagan South and Seaway projects and also the Philadelphia Rail project [inaudible]. So there’s a number of things that we’re doing in the immediate that I think are going to move volumes where they need to go long in advance of a project like that, or our own Northern Gateway project.

Robert [Inaudible] – Macquarie

Okay, thank, you.

Operator

Thank you. I’d now like to turn the call over to Sanjay Lad for closing remarks.

Sanjay Lad

Great. Thank you, Tracy. We have nothing further to add to the conference call at this time, but I’d like to remind you that I will be available after the call for any follow-up questions that you may have. Thank you and have a great day.

Operator

Thank you for your participation in today’s conference. This concludes the presentation, you may now disconnect and have a good day.

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