THOMSON REUTERS STREETEVENTS EDITED TRANSCRIPT/media/EepEeqMep/...Brian Zarahn Barclays Capital -...

1

THOMSON REUTERS STREETEVENTS | www.streetevents.com | Contact Us © 2014 Thomson Reuters. All rights reserved. Republication or redistribution of Thomson Reuters content, including by framing or similar means, is prohibited without the prior written consent of Thomson Reuters. 'Thomson Reuters' and the Thomson Reuters logo are registered trademarks of Thomson Reuters and its affiliated companies.

THOMSON REUTERS STREETEVENTS

EDITED TRANSCRIPT

EEP and MEP Investor Day 2014

EVENT DATE/TIME: APRIL 02, 2014 / 12:30PM GMT

http://www.streetevents.com/

http://www010.streetevents.com/contact.asp

APRIL 02, 2014 / 12:30PM GMT, EEP and MEP Investor Day 2014

2


C O R P O R A T E P A R T I C I P A N T S

Sanjay Lad Enbridge Energy Partners - Director of IR

Mark Maki Enbridge Energy Partners - President

Guy Jarvis Enbridge Inc. - President, Liquids Pipelines

Byron Neiles Enbridge Inc. - Senior VP, Major Projects

Greg Harper Enbridge Inc. - President, Gas Pipelines & Processing, Midcoast Energy Partners LP, Principal Executive Officer

Terrance McGill Midcoast Energy Partners - President

Steve Neyland Enbridge Energy Partners - Vice President, Finance

C O N F E R E N C E C A L L P A R T I C I P A N T S

Brian Zarahn Barclays Capital - Analyst

Chuck Goldblum Hurley Capital - Analyst

John Edwards Credit Suisse - Analyst

Ted Durbin Goldman Sachs - Analyst

Mark Reichman Simmons & Co. - Analyst

T.J. Schultz RBC Capital Markets - Analyst

Ross Payne Wells Fargo Securities - Analyst

Noah Lerner Hartz Capital - Analyst

Yves Siegel Neuberger Berman - Analyst

Larry Mondschein CRA Funding - Analyst

Sharon Lui Wells Fargo Securities - Analyst

Rob Vogel Lucas Capital - Analyst

Jeff Birnbaum UBS - Analyst

Jerren Holder Goldman Sachs - Analyst

P R E S E N T A T I O N

Sanjay Lad - Enbridge Energy Partners - Director of IR

Good morning and welcome. My name is Sanjay Lad, Director of Investor Relations for Enbridge Energy Partners and Midcoast Energy Partners. This year we are

hosting a combined investor day for both Enbridge Partners and Midcoast Partners. Among the management team we have a Wisconsin Badger and a Kentucky

Wildcat, so definitely some rivalry in the house.

In the spirit of safety, let's start with a brief safety moment. (Conference Instructions). As a reminder this presentation is being webcast. If you have any questions,

please wait for the microphone, state your name to identify yourself and your firm so that people listening on the webcast may follow along.

This presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined both on the slide and in the most

recent SEC filings for both Enbridge Partners and Midcoast Partners and we incorporate those by reference today.

With those opening remarks, it is my pleasure to introduce Mark Maki, President, Enbridge Energy Partners.

Mark Maki - Enbridge Energy Partners - President




3


Good morning, everybody. I will let you figure out who is the Wisconsin guy and who is from Kentucky based on accents.

I want to welcome everyone here to the Enbridge and Midcoast Investor Day. [We] Very much appreciate you all coming out this morning and joining us for breakfast.

Big lineup today, lots of discussion. We will be busy through lunch although I expect at different points in time we will pick up a little bit of speed as we go.

I want to introduce the primary speakers today. You've got myself, Mark Maki, President of EEP, going to be followed by Guy Jarvis, who is the President of Liquids

Pipeline Division for Enbridge Inc.; Byron Neiles who heads of our Major Projects Group and a very important discussion today is how we plan on executing in all the

major projects we have under construction. So Byron is here, he has been here off and on over the years but a very important element of today's presentation.

Greg Harper, President of Gas Pipelines and Processing for Enbridge Inc. is also speaking today and he is the Principal Executive Officer of Midcoast Energy Partners,

and he will be joined by Terry McGill, who is a key part of his team that everyone knows here very well. And then Steve Neyland is our cleanup batter, batting cleanup

today for us, our financial leader for EEP and Midcoast.

A number of other executives in the room from Enbridge. They are there, you'll know it by the name tag or the 811 lapel pin that we are with Enbridge. Feel free to ask

questions of anybody that is here. We bring extra folks so you can pull someone aside, have a conversation with them. If they don't know the answer they will find the

person who can help you out.

I also want to thank our IR staff who do a lot of work on this. It starts with Sanjay but Claudette Dionne, Jennifer Waller, Joel Smith, Teri Majer and others make this

happen and make it easy for the leaders to get through the session.

I want to start my comments with a few points on our base business and the slide here shows at the bottom in the yellow box one of the most important things at

Enbridge that we hold near and dear, it is part of our corporate culture, our basic values is safety and integrity.

Safety is the top priority for management at Enbridge. We spend a lot of time thinking about it, we spend a lot of time acting on it. We have made some very substantial

investments in our systems over the last several years to ensure that we are operating the safest pipelines in North America and our objective as a management team is

to become the leaders in safety and system integrity.

The next key message on the slide is with respect to our distribution being sustainable and certainly with the events of the last little while in the MLP space, this is a

very important point. EEP has been around since 1991 and if you think about the MLPs that were around at that point in time there is only a couple of them and there is

one besides us that is basically left or hasn't been taken over by somebody else.

We have never cut our distribution through any number of up cycles and down cycles in the business. Now in 2013, we didn't raise our distribution, that decision rested

with management, but I certainly expect that we should resume distribution growth in 2014. I would be very disappointed if we don't.

Our target is noted there at 2% to 5% per year and I will talk more about that later on.

We do expect our coverage to improve in 2014. That was a key element of our guidance call earlier this year, and we expect that our distribution coverage will continue

to improve in 2015. We will expect that we will be around the one [times] coverage in 2015. That will be driven by a number of projects that have begun to contribute

to our results this year, additional projects we will complete in 2014, and Steve will comment more on that and he will show you a buildup of that over time.

Now the confidence we have in our distribution and our outlook and our ability to grow always comes back to our base liquids pipeline system. Nobody else in the MLP

space has an asset package that looks like our system around the Great Lakes, the old Lakehead system or our North Dakota pipeline system in the Bakken. So again

our asset position is really one of the key things that we point to or what gives us confidence about our future in EEP.

Executing the growth program is very important to us and we are as a member of the Enbridge family very uniquely blessed and positioned and another reason we've

got Byron here to talk to us today is about our ability to execute on these major projects, get them done on time, on budget and perform as they are supposed to.

In terms of investment highlights mentioned before, EEP has been around a long time and over that period of time it has been an attractive investment for investors if

you look at our performance over our entire history. Now certainly there have been ups and downs in our history since 1991; 2008, 2009 certainly stands out as a dip in

the chart. But over that time we have seen competing pipelines built, we have seen the up and down cycles in the commodity markets. We have seen a lot of changes in

the space. We went through the Marshall incident in 2010, we have been through a rate case and over that period of time, we never have cut the distribution. This

management team understands how to work through difficult periods. Our financial plan does not call for a cut in distribution. It calls for management to grow the

distribution. That is the key message I want to get across today. We are here to grow EEP's distribution.




4


On the debt side, we recognize there are investors here in the bonds of EEP and certainly when you look at the ratings of the bonds, been very steady, three of the four

primary agencies in the US and Canada rate EEP's debt, Dominion Bond Rating Service out of Toronto, S&P and Moody's here in New York and Toronto.

Again very good rating relationship with the ratings agencies. We do take their advice into consideration, their counsel into consideration when we design our financing

plans and that was key to us in 2013 which was a very busy year for us in terms of financing activities.

On a go forward basis, Steve Neyland is going to talk about our equity requirements in EEP and they are relatively modest as we look ahead at the next five years and in

fact if capital is lower than what we are planning for in our plan, that equity need could be even less than what we show. On the debt side, we do expect we will become

more active in the next few years.

Now I always talk about this in any presentation I give. I think it is really important in light of again recent events in the MLP space and that is the strength of Enbridge

Inc. as general partner. It is one of the key distinguishing characteristics that EEP has relative to other MLPs in the space. Enbridge of course is a very large company.

Equity market cap, whether you are looking at the Canadian Exchange or the US Exchange is somewhere around $40 billion, north of $40 billion in Canada, a little bit

less than $40 billion here in the US. Again, so a very big company, many times the size of EEP.

Enbridge over the years has demonstrated a consistent support for EEP whether it has been in the form of financial support over the years or operational assistance

through the major projects group. We have seen nothing but again Enbridge being very supportive and it is clear when you look at the map why that is. EEP's systems

are at the heart of the Enbridge pipeline system. So we are very aligned strategically in what is -- it is important for Enbridge Inc. that EEP be successful.

So a couple of examples of that support recently, they recently announced Line 3 project replacing our existing infrastructure with a new pipeline. Enbridge Inc. has

proposed a joint funding of that project. It's a very large project but joint funding makes it very doable for EEP to take on a sizable component of that project which it

otherwise couldn't do the entire thing on its own. So Enbridge steps in and helps EEP fund that project.

In addition, last year Enbridge took a $1.2 billion preferred equity interest in EEP. This is after doing numerous common investments over the years and other joint

funding arrangements. Again, Enbridge has been a very supportive general partner and is very motivated to see EEP be successful.

In terms of strategic position, I mentioned this already, but we have one of the most powerful positions in North America when one looks at our access to supply, the

Western Canadian oil sands is a tremendous story. There is no other like it in the world in terms of longevity of the supply, our asset position in that basin. And then

North Dakota, again another great story. We are the primary carriers out of both of those markets. So the size and scale of our access on the supply side is tremendous.

On the market side we have access to the best refining complexes in North America. If you look at the midcontinent refining complex around Chicago, access now to

the Gulf Coast in and around the Texas market, the Eastern Canadian markets again, we have unparalleled access to markets. It is one of the key things our shippers

enjoy on our system is the optionality they have to go to different markets and realize the best value for their commodity.

We are currently in the middle of some major expansions of our systems. The chart here shows the addition of capacity to various markets including the US Gulf Coast

and that is a key development for us that is going to happen here in 2014. 600,000 barrels a day of enhanced access to the US Gulf Coast primarily for heavy oil. In

addition, you see the markets in Eastern Canada added over a series of three years 300,000 barrels a day. Again, a critical addition and change in the way the North

American energy infrastructure is currently set up as it opens new markets for light oil which is especially critical for the Bakken.

In addition, you see other markets including the upper regions of Pad 2, the Eastern regions of Pad 2. We are in the middle of a very major re-plumbing of North

America.

In terms of commercial structure, we've had this chart for a number of years so one of the things you see as you look out towards the end of the planning horizon is a

substantial step up in the cost to service component of our revenues. This is driven by pre-programmed dropdowns of additional interest in our Line 3 expansion, the

Eastern Access Expansion and our Mainline Expansions we have underway in addition to the Line 3 system entering service.

So what you are going to see over the next several years is a progressive transformation of EEP to more and more cost of service and the reason that is important is the

nature of cost to service is highly certain, very predictable cash flows and for an MLP, that is critical. So as we look at our plans going forward, it is one of the reasons

that we have a high degree of confidence in our ability to grow the distribution is that as these projects come into service they provide certainty of cash flows and that is

what underpins management's confidence about the future.

In addition, we are going to benefit from growth in volumes, no question and Steve again will touch on that in some of his prepared remarks.




5


But over time you are going to see our system become more and more cash flow certain through the addition of additional cost of service projects.

This will lead to strengthening of distribution coverage. I already touched on this but I want to hit on it again. 2014 we expect to be someplace between 0.85 and 0.95

on coverage. That was the guidance number at the beginning of the year. We expect we will be around 1 in 2015 and then we will see our coverage strengthen

thereafter. Now there will be periods of time it will go up or down based on where we are with our capital deployment but we certainly expect over the long run our

coverage is going to be strong and as our cash flows become more and more cost of service like, in high degree of certainty around that.

Now I touched on this some already. This is again a very important slide. We did a lot of work in 2013; it was the primary concern. When we were here last year a lot of

questions we got were how are you going to fund all these projects you've got under construction in the liquids business? We made a lot of progress in 2013 covering

off those concerns.

One of the key things we did and I mentioned this already was the $1.2 billion private placement with Enbridge Inc. This is a very important piece of equity capital in

our capital structure. In addition, the Midcoast IPO is an important part of how EEP is going to fund its projects in the future and at the same time provide a

preprogrammed source of growth to Midcoast through additional drop downs of the assets. We exercised an option to pare back our interest in a couple of our large

projects, but we have the ability to call that back in the future when the projects enter service. So again, that is again a very important feature that we triggered in 2013.

We announce the joint venture with Marathon on the Sandpiper project and got that project moving ahead. So again a lot of progress made on the financing side. So

much so that we have really knocked off most of our equity requirements, again as Steve will touch on a little bit later on today.

I mentioned Midcoast in the last slide and want to hit it again here. A key element of our future funding is going to be using the Midcoast structure to drop-down

additional interest in the natural gas business that EEP owns to fund our growth on the liquids side. We are very happy to have the Midcoast structure in place and we

are very happy to have Greg Harper on board to help us run that vehicle.

Midcoast is an important part of our future, and we think it is very important for Midcoast to have enhanced access to capital. So having it be its own vehicle will

enhance its ability to grow, be responsive to market opportunities and Greg will speak more about that in his strategies for the business in his section.

Looking at our growth outlook, the first couple of points I am going to pass over, I think you all understand those and really focus on the last one here which is

positioning EEP to become a drop-down vehicle for Enbridge. This is a very important strategy to EEP and Enbridge and we expect to be able to execute on this in the

future. Enbridge completely understands the value of the drop-down structure. We use it a lot in Canada for our income fund, ENF in Canada; we drop assets to that

vehicle routinely, and it is a great way to grow that vehicle and to monetize assets that are mature, good cash flow assets and that has been a key part of our strategy up

there for a number of years.

Enbridge wants to do the same thing with EEP and certainly as we come out of the organic growth phase that we are in we will go through an inventory of assets

shortly, there is a lot of assets at the parent level that can be dropped to EEP. But the first ones will be those preprogrammed calls, the ability to call back part of Eastern

Access, part of the Mainline Expansions and the Line 3 project once those assets enter service.

So coming back to what does this mean for distribution growth? We have had this slide for a number of years and we are consistent. We believe we can grow our

distribution 2% to 5% on an annual basis as we look ahead to the future. It is driven by the very large organic growth projects we have underway in the liquids business.

I teased you with this and I want to talk about drop-down potential from the parent. Now this is not an exhaustive list but it is meant to show you some dimensions or

potential size to future drop downs from the parent. You see a list of the various assets including Eastern Access, the Mainline Expansion, Alberta Clipper. These are all

assets that are part of the Partnership's portfolio to date. Line 3, which will be part of our portfolio in the future as we replace the existing line.

Flanagan South and the Seaway Twin are examples of systems that are today owned by Enbridge or joint ventured with Enterprise. The total of those is easily in excess

of $10 billion and that did include a whole bunch of other assets that potentially could be on the list. The point here is Enbridge has a lot of assets that can be dropped to

EEP in the future and certainly that is an expectation that we will trigger our options to call back some of our major projects and then as we migrate to a less organic

growth in the future, we expect that we will be available for drop downs for the parent.

One last kind of key slide here and that is to touch on again the importance of operational reliability, being project execution. We will let Byron speak to project

execution in his section, very important. But on the operational reliability side again over the last several years, you all know we have made substantial investments in

our system in terms of integrity of our pipelines and that continues to be a focus for management. In addition, we are deploying some of the latest state-of-the-art

technology to inspect and ensure the condition of our pipelines. We understand how they are behaving, how they change over time and we are taking the actions that are

necessary to make sure we operate the safest systems in North America. That is a commitment the Company has all the way through.




6


So, I will leave you with the key takeaway slide. I won't read those off to you and just move to a few minutes of questions. I'm going to try to keep my stuff at the high

level for EEP and save your detailed liquids questions and gas questions for Guy, Terry and Greg.

So with that, folks with the mic, any questions?

Q U E S T I O N A N D A N S W E R

Unidentified Audience Member

(inaudible) On slide 6, you showed the cost of service going out to 2017. What does that do in terms of the ownership of (inaudible) 100% ownership? So the question

is on [this] slide [for] 2017, what does that assume in terms of the ownership of some of those joint venture pipes?


That we are upsizing or taking our 15% options back on Mainline Expansion, on Eastern Access and it also assumes the Line 3 project enters service. There is a bump

from really all three of those different components. Line 3 is a big project.


If we could kindly ask folks to identify themselves and their firm so folks on the webcast can follow along, that would be appreciated.

Brian Zarahn - Barclays Capital - Analyst

Brian Zarahn, Barclays. Mark, can you give a little more color on the drop-down story in terms of when that could start taking place and maybe -- you gave the book

value of some of those assets, what do you think about on an EBITDA basis, a rough number?


First off, Brian, in terms of kind of the overall book value, so $10 billion is kind of a generic estimate as to what the book values basically would be on the lot of the

assets. The first series of drop downs would be the calls that we have which basically calls at book values. So those are great deals. In terms of EBITDA multiple, they

would be attractive, we will just leave it at that. The subsequent drop downs would be a negotiation between EEP and Enbridge, but again that again would expect to be

more of a -- probably not as attractive a multiple as the first drops but still attractive to EEP and Enbridge. Back of the room.

Chuck Goldblum - Hurley Capital - Analyst

Chuck Goldblum, Hurley Capital. So following up on the drop-down question, in the past the comment had been we have so much equity to raise here at EEP and EEQ

that drop-downs don't make sense now. Now the story is a lot different. In the next few years your equity requirements are a lot lower. That is number one.

Number two, on the Enbridge Inc. calls, they talk about not dropping down to EEP over the next few years as it relates to a higher cost of capital at EEP yet with a

lower growth guidance you are sort of left in this conundrum of what is going to bring cost of capital down. So it seems like you have the equity wherewithal to do drop

downs now yet with the low growth guidance it will never compete with other alternatives. Maybe, can you talk about that a little bit?


Sure, Chuck. I think the way we'd look at it as far as timing to us, really the logical first drop downs are the calls that we have in those existing assets. That is the place

I think we would make the transition. We still have to go through the execution phase of getting our projects done and getting them in service and performing as




7


expected. Again, we don't expect that to be a huge issue with again, as Byron will describe, we are very well equipped to get things done on time, on budget. We are a

good asset operator, so I think all those things are things we can execute on and accomplish.

I do think though, Chuck, that once we begin to see the organic growth activity decrease and we begin to see those drop downs come in and people understand the

transition that we are making to really a cost of service style structure very reliable, very reliable growth, very stable and protected downside, that we will see our yield

come down and we will become more competitive in terms of being able to do the drop downs from the parent.

So it is a bit of a journey. It is nothing we can do overnight but we see a path to seeing EEP migrate to a drop-down vehicle.


I am sorry, just a quick follow-up. So really so the takeaway then this we've got lots of drop downs to do but you are not going to see it for a period of years while we

work through the -- all of this organic we are doing?


Yes, we want to position for the future, Chuck. That is the idea. We want to position EEP to become a drop-down vehicle in the future. Right now execute on the

organic, that is our primary focus.

John Edwards - Credit Suisse - Analyst

John Edwards, Credit Suisse. Just following up on the drop-downs, you were talking about an attractive multiple or attractive return I guess. Would it be fair to say as

far as defining attractive that when you get through the organic growth phase here and you get into the drop-down phase that that would be taking your distribution

growth prospects up to the higher end of your range or is that a fair understanding of the word attractive or maybe you can give us a little more definition to that.


I won't get into multiples, John, today, that is probably not -- it is getting a little ahead of the game. But certainly the initial drop downs that we would do in the calls,

they are book value calls so those are I think very attractive for EEP in terms of our ability to grow I think at the higher end of our 2% to 5%.

One more question and then we are going to get the next person up.

Ted Durbin - Goldman Sachs - Analyst

Ted Durbin, Goldman Sachs. So you talked about you expect to grow the distribution in 2014 and yet coverage is below 1 times. How do you get comfortable talking

about expecting to grow [and] maybe 1 times next year, just kind of what is that balance between distribution growth and coverage?


That is a good question, Ted. Historically we have been comfortable with the idea that we can be a little bit less than 1 coverage and still grow the distribution at the

same time. What we are looking at is managing the long term and so as long as we see that balance being appropriately struck between the payout ratio that we have and

the return to above 1 coverage -- and that has been certainly our expectation -- that we would be comfortable bumping the distribution modestly and then as we improve

our coverage looking at moving into the higher end of the range as John was alluding to.

So as we get further out in the plan, we would expect our distribution increases to ramp up from what they might be at the front end.

I think with that, I'm going to pass off to Guy. We will come back for more questions at the end if there is anything else that folks want to follow up on.





8


Guy Jarvis - Enbridge Inc. - President, Liquids Pipelines

Thanks, Mark. Good morning everybody. Happy to be here today to talk to you about our liquids pipelines business. As Mark mentioned, Vern Yu, who is our Senior

Vice President of Business Development, is here as well today. He has been intimately involved in a lot of what I'm going to talk to you about today so feel free to seek

him out if you have any questions that I haven't been able to answer to your satisfaction.

I now have 59 minutes and 33 seconds to talk to you about liquids pipelines and allow some time for questions. So I am taking the approach of a pretty high-level run-

through of my remarks, trying to make sure we leave ample time for addressing any questions that you have got.

So let me kick off, much as Mark did, with our key messages. Crude oil fundamentals continue to be strong for our business. Our commercially secured market access

programs have extended and bolstered our competitive reach. We are the premier liquids pipeline system to offer shippers access to multiple markets. Finally, we know

that secured projects don't translate into operating and financial success without a significant day in, day out attention to the discipline and focus that we need on all of

our assets. We are committed to doing just that.

Mark did a really good job of introducing safety and operational reliability as the top priority of all of our business units. I'm going to come back to that later. I think the

way this slide is pictured, I think is very apt. I view safety and operational reliability as the foundation of our ability to do everything else in the business. So we will

come back to that but I want to reiterate from Mark's remarks that it is the top priority of our business unit.

We talked about having strong fundamentals not only throughout North America but across the footprint of our assets. We are extremely well positioned to serve the

growing heavy oil production in Canada as well as the continuing light oil Renaissance particularly from the Bakken formation.

US refining market appears to be fairly stable in the coming decade. Growing Canadian and US production is continuing to squeeze out waterborne imports into the US.

Accessing in the refineries to displace these imports is a critical element of our market access story that I am going to speak to in a few minutes.

As a pipeline company, we are looking to help our customers access the most profitable supplies and markets. In particular, producers in Canada and the Bakken are

looking to minimize the price differentials they realize from the various benchmark crudes. We have seen some improvement in that regard for both but as the chart

indicates when we look forward and see growing supply, flat demand and continuing pipeline bottlenecks, considerable price volatility has arisen and we think it could

continue into the future.

Pipeline capacity is not keeping up with the potential production outlook. It is going to be a few years, and I'm going to speak further about this next, it is going to be a

few years before the pipeline capacity takeaway matches up with the supply curve.

There has been a lot of talk about pipeline capacity in the last number of years both in the industry, regulatory, public and I think this slide is a good indication of why.

Looking at Western Canada, takeaway capacity is barely forecast to keep up with production and does not have the potential to reach an optimal level for industry until

approximately 2018 when some of the projects that are currently in the early stage development are forecast to come into service. We see Keystone XL coming on late

2016 and some of the other projects by as soon as 2018. But as the different coloring on the chart suggests, these dates can easily slip given uncertain regulatory

timelines. While these slippages would not be good for industry generally, if they do occur it may in fact be good for Lakehead as our assets will largely be in the

ground and ready to move to crude.

The story in the Bakken is similar to Western Canada. However, we see the picture easing in 2016 once we put our Sandpiper project into service. Rail is obviously

filling the void of the current pipeline capacity shortfall, but we are confident that once Sandpiper is in place and our light oil market access initiatives are complete we

will have a competitive advantage versus rail to a much broader range of refineries.

The wildcard here still relates to the production outlook. Enbridge has tended to be more conservative than many others and the formation continues to prove us wrong.

If the production continues to grow to the upper ranges of other forecasts, there will be even more opportunity for new pipelines in this region.

Our competitive advantage draws largely on [the] strategic position of our pipeline footprint. We are attached to growing supply, we offer access to multiple refineries

directly served off of our system or via downstream pipelines with which we connect. We operate a significant network of substantial terminals across our system that

allows us to offer our customers unparalleled flexibility and we can leverage the size and scale of our operations to offer competitive tolls. This asset base positions

Enbridge Energy Partners and Enbridge to be very well aligned with a great outlook for long-term growth.




9


Our secured market access programs, Eastern Access, Light Oil Market Access and Western US Gulf Coast Access are slated to open new markets for up to 1.7 million

barrels per day of crude in the coming three years. An additional 1 million barrels per day of heavy oil will have access to markets in the Midwest, Western Gulf and

Eastern Canada while 700,000 barrels a day of light oil will have access to Patoka, Sarnia and other Eastern Canadian markets.

As you will recall from our public disclosures on these opportunities, they are all commercially secured, no risk arrangements underpinned by long-term contracts.

Eastern Access targets refineries in Ohio, Michigan, Ontario and Quebec, which can consume both heavy and light barrels. As the slide indicates, many of the elements

of this program are already in service. As we speak, we are now working to bring the first phase of the Line 6B replacement into service with the full replacement and

the Line 9B reversal all expected to be complete before year-end. That will bring all of the elements of this program into service.

As with Eastern Access, there are a number of elements to our Light Oil Market Access program that is targeted at moving Canadian and Bakken light oil supplies to

refineries at Patoka and Eastern Canada. These initiatives will come into service between later this year and 2016 when the Sandpiper and Southern Access Extension

projects come into service.

Access to the refining centers of the Western US Gulf Coast via the Enbridge system will improve dramatically later this year when our Flanagan South pipeline and

Seaway Twin projects are slated to come into service. This added market access will require that we expand our Mainline system as well to ensure barrels can reach

Flanagan and ultimately the Gulf Coast.

I talked earlier about the supply growth in the Bakken. Upon completion of the Sandpiper project in 2016, the Partnership's pipeline takeaway capacity from the region

will reach 585,000 barrels a day. Our Berthold rail facility offers an additional outlet of 80,000 barrels per day. While all of the above is again commercially secured,

there is still significant opportunity to invest further in the gathering pipelines necessary to bring local production to our takeaway pipelines. We will be aggressively

focused on firming up and securing these opportunities.

I mentioned Sandpiper a couple of times so far this morning. So let me quickly remind you what this project is about. Sandpiper is a $2.6 billion project to construct a

new 24-inch pipeline from North Dakota to our Mainline at Clearbrook and a 30-inch pipeline from Clearbrook to Superior. The system will provide 225,000 barrels a

day of capacity out of North Dakota and 375,000 barrels a day beyond Clearbrook.

As we have previously disclosed, Marathon has signed up as the Anchor Shipper on the system along with an arrangement to fund 37.5% of the construction costs

which will be converted into an approximate 27% equity interest in our entire North Dakota system.

Our most recently announced project is the agreement with our shippers to fund replacement of our Line 3 through a toll surcharge. Given that our system will be pretty

much in balance following the expansions of Alberta Clipper and Southern Access, the Line 3 replacement does not offer substantial longer-term volume upside in and

of itself. It does offer Enbridge much greater flexibility to manage flows across our system during times of planned and unplanned maintenance thereby ensuring

shippers a higher degree of certainty as to meeting the expected throughputs of our system. As disclosed, this $2.6 billion project will be jointly funded by the

Partnership and Enbridge.

I have focused a lot on what our market access programs offer for our customers but the benefits for Lakehead are expected to be substantial as well. We are already

seeing the strong demands on the system and have experienced varying degrees of apportionment so far this year. The barrels are there and they are continuing to grow.

By creating access to in excess of 3 million barrels per day of refinery connections in downstream markets we believe Lakehead is very well positioned strategically,

commercially and competitively to very successfully grow the volumes across our system.

Mark has talked, [and] I've mentioned safety and reliability so let me talk a little bit more for what it means to us at Liquids Pipelines.

We are striving to be the industry leader in all key safety categories, pipeline integrity, leak detection, emergency response, worker and public safety, and we believe it

is no longer simply a nice to have. Being the industry leader will further entrench our social license to operate in the communities that we traverse, and we believe it can

become a competitive advantage. We spent a tremendous amount of financial and human resources over the past number of years targeted at creating that advantage and

we can see the payoff coming.

We have replaced or are replacing significant portions of our system with new pipe, which not only reduces future integrity costs but we are earning on these

investments as well and the significant effort of our recent years' activity now position us with a very complete picture of our system that will allow for an ongoing

more focused approach to our spending.




10


So in closing, I would just like to reiterate our key messages. The fundamentals are strong, Lakehead is competitively positioned and offers the broadest market access

opportunities of any North American pipeline, our focus on operating and financial success is sharp and safety and operational reliability is what allows us to make all

of the above happen.

Thank you for your attention and I would be happy to address your questions.


Mark Reichman - Simmons & Co. - Analyst

Mark Reichman, Simmons. On the last call on the Line 3 replacement program, there was a lot of talk about balancing capacity in and out of Superior. What I want to

do is, I have been getting a lot of questions regarding capacity in and out of Flanagan. And so it is kind of confusing, but with Line 61 capacity at 400,000 barrels per

day and that is expected to grow to 560,000 barrels per day in the third quarter of 2014, I am just wondering how you are going to be able to feed 235,000 barrels per

day into Line 62 and then 190,000 barrels per day into the existing spearhead line and have much left to fill the Flanagan South.

So I am just wondering whether Flanagan South is going to be operating under capacity for a while or whether you are going to need to add capacity above Flanagan?


So there's a few questions in that question so let me tackle them. First of all, in terms of the capacity growth on our system by the end of this year, we expect that we

will have the capacity on the Lakehead system up to about 2.5 million barrels per day. Later on as the phase 2 -- when we ultimately get Alberta Clipper permitted and

fully in service, that capability will be up to about 2.8 million barrels a day.

In terms of throughputs, so that is without any capacity restrictions -- that is before you take into account any operating anomalies. So when we look at having

ultimately 2.8 million barrels per day of capacity, and we look at the way our system operates in terms of where barrels come into it where we make deliveries off of it,

you can't move 2.8 million barrels per day every day. So when we look out into that 2017 timeframe post-Alberta Clipper, post Line 3, we see that we will be moving

about 2.6 million barrels per day.

If I back that up to I think your Flanagan South question, Flanagan South we do not expect it to come on and run at its full capacity. When we spoke about that project

at the time that it was done we indicated that there would be tilted returns on that deal for Enbridge and really the tilted returns come from the fact that our contracted

customer volumes actually increase over a period of three to four years. And in terms of how much moves on a spot basis, the market will decide that.

So we are watching this very closely. When we look at this summer and this fall and Flanagan South coming into service, our assessment of it is that the balance of

barrels is going to be very tight and where those barrels choose to go on our system whether they go down Flanagan South, stay in Chicago or move elsewhere is going

to be a function of the market prices.


Okay. And then the Line 61 expansion addition of 640,000 barrels per day, I had that down as 2015. So that is 2016. Would you expect that to be early 2016 or when in

2016 would you expect that expansion to be completed?

Unidentified Company Representative

(inaudible - microphone inaccessible)


1.2 million by when?




11



Byron says he is going to cover that when he speaks about major projects.


I will give back the mic.

T.J. Schultz - RBC Capital Markets - Analyst

T.J. Schultz, RBC. Just on Sandpiper, so Anchor Shipper secured, if you could just comment on conversations with other potential shippers. And then you have filed a

petition with FERC, just next steps there in your line of sight or comfort level with the in-service date?


So you are correct, Marathon is our Anchor Shipper. We ran a subsequent open season and did have some limited success in attracting some additional barrels. The

way I would probably describe the situation there is that people are now looking at the fact that that capacity is going to be built that we are going to have common

carriage capacity available as part of that program that they can now access. So many of them are simply content to rely on competing for the common carriage

capacity.

The Bakken is a very difficult place to secure contracts for [the] long-term to build new pipelines. We are very happy to have Marathon on board that it is a quality

credit with a market on the end that really makes a solid project, but they are very difficult to do in North Dakota.

In terms of the PDO, we have filed it. We have obviously consulted with FERC a lot on that because our first attempt at the PDO didn't work out very well which led us

down the path of where we have landed with Marathon. But we feel quite strongly that that PDO is going to be dealt with in a fairly quick fashion. In fact I think we are

hoping that we may hear back in May on that.


Brian Zarahn, Barclays. I guess on the heels of Line 3, can you talk about the potential need to replace other portions of pipe in your system? And then we have a lot of

oil pipe outside of Enbridge just industrywide. Your view on the industry's potential need to start replacing some old pipe.


I think we have been one of the largest proponents of making sure that the public doesn't fall into the trap of assuming that the age of the pipe is the only consideration

in terms of the quality and integrity of the pipe. I think many of you have probably heard some of Steve Wuori's past stories about digging up some of our oldest

pipelines that were cold tar coded and finding that despite the fact they were put it in the 1950s and 1960s they are in pristine condition.

So we really take an individual, not just a pipeline, but a segment by segment approach to evaluating the integrity of our pipe and Line 3 I think is a good example of

that. Where we had identified on Line 3 that we had three sections of that system where we were going to go forward with the pipe replacement.

There [were] a couple of others that were kind of on the edge of the engineering analysis of what is the best thing to do. And in consultation with industry came to the

conclusion that the best thing from an integrity perspective, the best thing from a reliability perspective, the best thing from an economic perspective was to replace it in

the manner that we are doing.

But what you may have noticed about part of that is that we are not replacing the section of Line 3 from Edmonton to Hardesty and the reason for that is that the

engineering analysis for the integrity of that segment and how it is going to be operated suggests that it does not need to be replaced.




12


So we are continuing to take a very surgical approach to the integrity of all of our pipelines, new and old and when you look at the system with 6B being replaced and

with Line 3 being replaced, the percentage of our barrel miles or however you want to characterize it that would be characterized as older pipe is coming down quite

substantially in that period.

In terms of the balance of industry, I go back to my introductory statement is I don't think you can make a broad brushed message about age versus integrity. Certainly

we know we have to continue stepping up integrity, integrity to mean a whole range of things -- in-line inspections, limited Hydro tests, other engineering analysis. I

think what we are very interested in is trying to see industry collectively migrating to an agreement on what is best practice.

We've got a lot of operators like ourselves who are doing kind of leading edge stuff around in-line inspections but we have many other operators in the industry who

aren't there yet.


And then I guess turning to rail, given delays in XL and Alberta Clipper, how do you view the growth of crude by rail out of Canada and I guess longer-term?


Our views on rail have changed -- I guess our fundamental view of rail has changed pretty substantially in the last year and a bit. I think if you went back and asked us

and you may have heard it from us a couple of years ago, maybe three years ago, we would be saying we think the room for rail is on the margin, at the top of the

production curve but it has proven to be more than that.

Rail has been very successful in getting into some of these refineries on the East and West Coast that are not well accessed from pipelines, and we have now concluded

that pipelines are probably never going to get those barrels back. So I think the rail business has captured some market that they are going to keep for the long-term. I

think we estimate over the long term that could be 100,000 to 125,000 barrels a day which traditionally we may have thought would come on to our system or others but

we think is going to stay on rail.

In the more near-term, we are seeing out of Western Canada the need for possibly as much as 350,000 barrels a day of rail movements through to that 2017 timeframe

that I referenced on the pipeline chart. Certainly the loading facilities are there. It is just at what rate will they get utilized, where are they going to go, how are all of the

potential new regulations going to impact the reliability and competitiveness of the rail deliveries?

Vern was mentioning to me yesterday a conversation that they had with one of our refiner customers who was expressing their disappointment at how rail wasn't

performing really well for them and it was not so much about the access and the competitiveness, it was about the lack of ability to forecast when the train was going to

show up at the refinery.

So it is not a failsafe outlet but they've certainly made better inroads than we thought.

Any more questions? I got the thumbs up from Steve. I guess we are still on schedule. Thank you very much. Sanjay, are we going to move on to the next speaker? We

will turn the microphone over to Byron Neiles.


Byron Neiles - Enbridge Inc. - Senior VP, Major Projects

Good morning. My objective today is to demonstrate how major projects, or MP as we call it, is able to execute the EEP growth capital program safely, on time, and on

budget. And to do that, I will take you through the MP organization, some of our competencies, and then I would like to highlight some of those competencies in action

by going through a sample of some projects underway today.

Enbridge wide today, we are currently managing 35 projects at $31 billion, which includes the recently announced $7 billion Line 3 replacement program. 11 of those

35 projects are part of the EEP capital portfolio.




13


Since MP was formed in 2008, we placed 30 projects into service at $17 billion at 1% under budget at the end of 2013. Enbridge has been a first mover on a number of

execution strategies including resourcing of materials, goods and services, and our track record is built on a seasoned and scalable workforce, which remains in place

today to tackle this very massive workload that is ahead of us. Then, we also have very strong and deep-seated supply chain relationships to position us well for

execution.

Our front-end planning approach sets the groundwork for permitting effectiveness by embedding environmental regulatory public affairs experts at the outset alongside

the engineers to make sure that any stakeholder issues or risks that emerge during our consultations are incorporated into permit applications to make the job of the

regulators much simpler.

Further, to what Guy said, we have a resolute commitment to safety and our path to zero incidents and substantial efforts are placed both internally and externally to

influence safety practices across industry recognizing that there are a number of owner companies across the USA and Canada who draw upon a similar pool of

contractors.

So with that key message context, let's move to the capabilities that help us achieve the track record that I have just outlined.

First, to structure and leadership. MP is led by six senior leaders with the addition in 2013 of a second liquids focused VP to handle the significant increase in capital for

execution in the US and all of these VPs have been former project directors throughout their careers. With $31 billion to execute, strong leadership is essential for sure,

but to support that leadership you need professional management in support of them so we have a team of 1,600 professionals, 60% of whom are contractors, which

allow us to seamlessly match resources with activity levels as that unfolds.

In the field today, we are leading several thousand more contractors in the field and that peaked at 10,000 in 2013. I expect that we will meet or potentially surpass that

major army, if you will, by the end of this year.

So, certainly the rapid scalability of a seasoned workforce supports our ability to generate value for the customers who put their trust in Enbridge and in EEP as well as

to sustain our strong execution record.

A major contributor is estimating and development practices. We have comprehensive project data for over 50 projects including the 30 completed in the last five years

as well as a number given we have several projects underway in construction this very minute. Using that data, we benchmark all estimates against recent experience,

and we calibrate with trends and with recent experience and lessons learned to make sure that we are competitive in the offerings we make to our customers.

The other added benefit is that Enbridge's projects tend to be in well-known corridors and rights of way, existing footprints and that helps lead to repeatable estimating

performance at the outset.

Then we drive towards standardized designs as much as possible like the pump station pictured here. That helps us to reduce engineering costs by ensuring that we only

have to design once and then repeat, but as well, it helps us to achieve supply chain savings through volume discounts.

Furthermore, we have learned over time that the use of fabricated modules and controlled environments and fabrication shops again helps to drive down costs, improve

quality and avoid the kinds of challenges one has in constructing in the field especially when it gets wet and cold.

The way we manage our supply chain relationship generates considerable value for our customers, our pipe agreements have provided better than market pricing since

2006 and reserve capacity through 2016. And what this does is it guarantees that we have the reserved mill space for all US projects. We know how it will be priced and

we know that it will be high-quality, hence no surprise, no risk.

Also such arrangements allow us to work with our supply chain to expand their capacity as we grow. So, this was evidenced last year by EVRAZ opening another pipe

mill in Portland and then in the same city, Sulzer, the company that we secure the majority of our pumps from, doubling their assembly line to ensure that they can meet

our increasing needs for horsepower expansions.

Historically in the US, the construction contractor capacity has been conducive to competitive tendering, the three bid and a buy approach, but given the increasing

activity here in the US, we are continuously looking at opportunities which can improve long-term execution efficiency and mitigate risk which we have been able to do

in Canada through long-term frame agreements with a number of select construction contractors.




14


What these approaches are able to do is to lock in fixed base lay and unit rate prices and that helps establish repeatable productivity because you continually use the

very best contractors from one project to the next so you get a very good rhythm not only in terms of your productivity and performance but also in terms of quality and

safety. And certainly there are a number of US contractors very eager to emulate the approach that we have already taken in Canada.

When you take the two together, when you lock up construction capacity at predictable terms and you couple that with a known price and pipe, you are close to

knowing 70% of your cost of your project very early before you are even moving any yellow iron.

Then we are of course constantly reviewing our organizational capacity relative to forecast workload to inform our recruitment plans.

As we all know given increasing opposition to infrastructure, it is no surprise that permitting cycle times from application through to approval are taking much longer

both in Canada and the US. That said, to date we have secured every permit we have ever applied for, and that is not to say that some aren't delayed from time to time

but as an overall measure of effectiveness since 2010, we have received all of the permits we have applied for, more than 80% of them on time.

One of the most noticeable changes we've seen in the permitting environment for energy infrastructure is how critical the involvement of our Company and third-party

experts in pipeline integrity as well as operations has become and it is a must with regulators, with counties, with first responders in the pipeline communities who

require a better command of the capabilities and the topics through face-to-face meetings with these experts.

It is also important that we build support of coalitions very early on by engaging customers, the labor community, business and community leaders and state officials as

seen here. This is Wisconsin Gov. Scott Walker who toured our Superior terminal about three weeks ago and held a news conference endorsing all of our projects, and

he isn't the only one. We have had a number of senior state officials, Gov. Nixon out of Missouri on another project as well.

As mentioned earlier last year, we directed 10,000 fieldworkers all of whom are temporary, many of whom are new and so certainly there is safety risk in the work that

we do day to day so our job is to maintain the momentum that has seen us reduce our recordable incident frequency by over half since 2008 and certainly this is among

the very best records on both sides of the border bar none against any of our other owner companies in that peer community. But certainly not good enough for us.

So, our momentum towards zero safety incident culture hinges on ensuring that our project and contract leaders are walking the talk on safety and reflecting that with

the men and women who they lead, the thousands of men and women who they lead in the field the controls that we have in place to place training and supervise and

ensure compliance of this massive contractor workforce. And then of course, increasing management visibility of the field not only management of Enbridge but senior

management, the presidents of all of the contractors who are working for us through hazard assessment, joint audits of the work, inspection and prevention.

One of the single most important things though that we can do to improve safety at Enbridge is to press industry both in the US and Canada to adopt similar practices

recognizing that contractors work for a number of owner companies and encounter different standards and practices and that leads to confusion and risk that we can

avoid if we coordinate together.

So in 2013, Enbridge brought together all of the major US owner companies as well as all of the major pipeline and construction companies to drive common practices

for the immense contractor workforce all of us draw from. And with industry approach, Enbridge will continue to lead this initiative with our next meeting in Houston

in May.

Our job, as I mentioned, is to manage risk and we do this with a lifecycle gating control, which every project must follow consistent cost and schedule management

approaches and regular performance reviews, not only within my organization but with the CEO, all of the business unit leads, many of them here in the room today as

well as with the Board of Directors, not only through written communication, but I present to the Board of Directors [for] both EEP and Enbridge Inc. Board members

at all of their meetings given their very keen interest in following our progress.

Focusing on risk at all stages of the lifecycle is very important quality, safety, production, regulatory, all of these key aspects can have an impact and so all of our

projects maintain detailed risk registers and manage and report on these risks frequently.

While these are essential to me, what sets us apart comes down to two things, a track record for repeatability and seasoned teams. Both are intertwined. We repeatedly

work our competencies and never ignore past projects and we learn from lessons from those projects which help the Company to secure and then execute on the next

projects.

So what I would like to do now is use a sample of five projects to demonstrate some of these competencies at work at various stages of the lifecycle. So looking first at

Eastern Access, the replacement of Line 6B through Michigan and Indiana, construction of the 160 miles between Griffith and Stockbridge is now mechanically

complete, ready for in-service this April, this month.




15


Then for phase 2, the remaining Eastern 50 miles to the Canadian border, we have cleared the entire right-of-way and we will begin construction this month when the

road bans allow us to get into service there and that project will be in service in Q3 of this year.

Then after the completion of the full replacement of 6B, there will be work involving pump upgrades and terminal work as well as the construction of five additional

tanks at Stockbridge all of this for 2016.

Phase 1 of the Clipper expansion project will see an additional 120,000 barrels per day added to the current 450,000 barrel per day capacity. Construction has gone very

well despite that we have had 70 days of below zero weather to contend with in Minnesota. But station modifications will be complete as scheduled in July on budget.

For phase 2, 230,000 barrels per day of capacity will be added through Horsepower bringing that system up to the total 800,000 barrel per day capacity and we are

currently engaged in six public meetings in Minnesota for the certificate of need. These started in March and the last one is tomorrow night in St. Paul.

At the same time, we are currently actively working with the Department of State in Washington on the required amendment [to the] presidential permit required to

increase capacity to 800,000 barrels per day, and based on where the process stands today, we know the amendment will take longer than anticipated, but we do expect

now to have that in place by Q3 of next year.

The third part of the US Mainline enhancement program involves the expansion of Southern Access. Someone asked about that earlier from 560,000 barrels per day to

1,200 thousand barrels per day and this project is also tracking on plan with these staged in service of 800,000 barrels per day by Q1 of 2015 with the subsequent

1,200,000 barrels per day by Q3 of 2015.

Bids for the station and terminal work have come in, they are in line with budget so award is underway right now and the planning for construction could get underway

for early May.

Then on the permitting side for the Southern Access Expansion, five of the 16 stations require a joint wetland permit between the state of Wisconsin, where Gov.

Walker is from and the US Army Corps of Engineers, which we expect to have in hand in Q3.

Moving to Sandpiper, we are currently in the planning and design phase of the 600+ mile pipeline from Beaver Lodge, North Dakota to Superior. The project's initial

capacity as mentioned earlier will be 225,000 barrels a day to Clearbrook and then 375,000 from there to Superior. To date, we have secured 56% of the right-of-way.

Most of North Dakota has already been secured, and we finished regulatory hearings on the certificate of need required in North Dakota during the end of February and

then we have recently completed public hearings on the Minnesota route options which will be followed by hearings to secure the certificate of need in Minnesota in the

early fall.

Moving to the Line 3, this as we mentioned, was announced not quite four weeks ago. It is the largest project that we will ever have undertaken. $2.6 billion represents

the US investment and to help ensure successful delivery, we have reassembled the execution teams on both sides of the border who successfully delivered the original

Alberta Clipper on time and ahead of budget in 2010. Both of the teams, the US and the Canadian teams are very familiar with the corridor and the issues and the risks

that are associated with large-scale and high-profile projects of this kind. Very intimate knowledge with all of the stakeholders along that right-of-way.

Much of our supply chain requirements are already locked down through frame agreements and we will continue to pursue those to ensure predictability. Detailed

engineering will kick off soon and environmental surveys are underway as is a very robust outreach program with regulators, land owners and key influencers.

Moving further south to the Beckville gas project, it is a 150 million cubic feet per day cryogenic gas plant which will capture NGLs from the existing Enbridge East

Texas system. The project progressing very well on procurement having secured key critical path items such as the cryogenic units. That is complete and most other

long lead items such as the amine unit and the hot oil systems were secured last fall.

On the design side, the construction bids were received, again in line with our expectations. We have awarded the contract and important as well, construction has been

authorized by the Texas Commission on Environmental Quality, so site preparation has been underway for about three weeks now and again in early May we can

mobilize the contractor that we have selected on-site to get that work underway.

So to sum up, project execution is a core competency for Enbridge and EEP that helps us to deliver the EEP growth program as I mentioned safely, on time and on

budget. This is certainly accomplished through disciplined controls, rigorous risk mitigation and extension governance and reporting and in combination with the use of

very seasoned teams, we are able to deliver repeatable execution.

So at the end of the day, execution is in Enbridge's DNA and the competencies we have outlined here this morning drive our confidence that we will be able to help

EEP deliver on its growth plans.




16


So with that I appreciate your attention and welcome any questions that you have.


Ross Payne - Wells Fargo Securities - Analyst

Ross Payne, Wells Fargo. When you are replacing Line 6B and Line 3, are you actually pulling the old pipe out and putting new pipe in or are you just laying

something next to the old line?


We will not be replacing much pipe. There are some requirements in certain regulatory jurisdictions but they are very, very small. So what we will do is insert nitrogen

into the existing lines, inert gas that will remain in the system and our operations people will continually monitor any potential for subsidence of the soil above those

lines and make sure that the right-of-way is maintained in proper order. But for all intents and purposes, the lines remain in place under the ground.

Ross Payne - Wells Fargo Securities - Analyst

Okay. Second of all, the pipe that you are putting in place, what type of pipe is that? Where is it manufactured and what kind of coatings are on the outside? And that

question really relates to an earlier comment by Guy on certain types of pipes holding up better than others. So what kind of design are you guys going for and what

kind of designs in the past have caused some problems?


So on 6B, the wall thickness will -- currently is ranging around a 0.25 of an inch, some of it thinner, but the new 6B will run closer to 0.40 of an inch all of the way up

to 0.63 of an inch depending on the need for railway crossings, wetlands and road bores, they require thicker steel. So thicker more resilient steel than that was used

decades ago and the coating is a fusion bonded epoxy which is the highest standard used in the industry today and there will continue to be cathodic protection applied

to the pipelines. Again, this is industry standard to ensure that any potential for corrosion is attracted elsewhere to sacrificial anodes.

Sunil Sibal, Global Hunter Securities

Good morning. Sunil Sibal, Global Hunter Securities. I just had a question on one of the slides, five, there you had a chart if you can go back to that, slide five. So

could you quantify for us the difference in rough order of magnitude between the two lines that you have there, the yellow line and the blue line?


Yes. So we have, as I mentioned, locked in. We have had a pipe arrangement with a company called EVRAZ who have mills on both sides of the border. We have

entered into a long-term arrangement where we are exposed only to the fluctuation in the price of steel but all other costs, overhead, transportation, a number of --

marketing for example, all of those costs remain fixed and so the net outcome is that since 2006, we have beat the market pricing by about 16% and we forecast to

continue to do that.


And that 16% is not total installed cost I presume?





17


The total?


Installed cost.


That is -- the total installed cost is not part of that equation. This is just for the delivery of steel. When we look at total installed costs, we would add in the cost of the

Mainline construction. That is a much more significant cost than the steel. Then you add on project management, you add on inspection, a whole number of other costs.

So this is just a comparison of our competitive advantage of the frame agreement that we have entered into for the purchase of steel.

Noah Lerner - Hartz Capital - Analyst

Noah Lerner here in the back. A quick question. Maybe I should know the answer to this or maybe it is just a bad question so I apologize upfront. But on page 12 on

the Line 3 replacement, it looks like the green line has taken a different path than the black line which I am assuming is the current path of Line 3. And I am just curious

why the path is different and what drove you to have to have or desire to have a different path to the replacement line than what has been in operations to date?


So the same rationale that we took an alternative route on Sandpiper and that has to do with everything from population. We are avoiding over 100,000 people by

looking at the alternative route, a number of communities that we bypass by looking at the other route. There are environmental considerations, a number of wetlands

that we are able to avoid. There is the Chippewa National Forest that, were we to go through it, would require a significant federal environmental impact statement and

we all know how complicated federal permits are to achieve.

And then there are cultural issues, tribal lands for example. There is sovereign tribal nations who have a number of aspirations and so the short story after having said

that is that this route both the Sandpiper and Line 3 is more executable. It is our preferred route. The other route will be considered by the Minnesota PUC in both

instances but our preference is this alternative route because it is indeed more executable.


Going back to my days of geometry, since you are not going on the hypotenuse, is it more costly but easier executable or it is not much difference in cost with this

alternative route because you are taking two routes?


There is an additional cost but we will be following two existing utility corridors, the Minncan Pipeline and then a Minnesota power transmission line. So there are

already significant energy infrastructure rights-of-way in place that we can follow and that was one of the other benefits of this particular alternative. For us, the cost

increase had to be offset with the risk of not being able to execute another route.

Yves Siegel - Neuberger Berman - Analyst

Yves Siegel, Neuberger Berman. Can you just describe the type of outside contractors that you typically use? And from the prospective, so you are procuring the steel

that you are responsible for.





18


Correct.


Then do you have a turnkey contract with contractors in terms of actually laying the pipe and the actual construction?


So we don't outsource turnkey management of the project to contractors. We will select the construction contractors, whether it is for Mainline pipe or for pump

stations or for terminal work or for tanks. But we believe there is no one better than our own teams to manage those contractors.

As I mentioned earlier, one of the things that we have done in Canada is that we have locked up over 50% of the Mainline contractor capacity as well as a percentage of

the pump station contractors and as a quid pro quo for us committing to use them over and over and over again, they are willing to provide us very competitive rates

knowing that they can keep their people employed from project to project and as I mentioned, we achieve rhythm in terms of productivity, safety and quality.

So on the US side, we will lead in managed construction, but we hire very seasoned and experienced contractors under our management.


And if you could, what is the highest risk on the project if you can generalize if there is going to be a variance, what part of the project are you most at risk using?


The most significant risk that I sense today is the regulatory and permitting environment and that is on both sides of the border and I don't think that is a surprise to

anyone. I am not concerned about supply chain, I am not concerned about availability of resources. I am not concerned about our ability to achieve productivity with

our contractors. It is the effect that intervention in the regulatory arena is having.

Now, I have said we have achieved every permit that we have ever applied for but we are seeing increasing cycle time so the in-service dates are being pressured as a

result of that pressure at the front end.

I never get this many questions at Enbridge Day. So thank you very much.

Larry Mondschein - CRA Funding - Analyst

Larry Mondschein, CRA Funding. On the Line 3 replacement, could you give me a little bit of perspective? I know when you announced it you said there was going to

be maintenance savings involved and also there was going to be an upcharge to the shippers. I was wondering if you could put those numbers in perspective against that

$2.6 billion in cost?


Can you repeat that please?


Yes. I recall that when this was announced that there was some offsets in terms of you were going to be saving operating costs by replacing this line.





19



We avoid a lot of capital work on Line 3 looking ahead into the future. That was one of the key drivers, a couple hundred million dollars easily over the next planning

horizon and then over the longer cycle substantially more than that. So a significant capital element that we would avoid. In addition, newer pipeline we have less

activity on it in terms of operating but not as meaningful. Really it was capital that was the issue.


There would have been a lot of segment replacement, piece by piece by piece rather than the entire replacement which was more economic to pursue.


So a little bit curious given the rich opportunity set that you have in terms of drop downs and other projects that you chose to do this replacement as opposed to

something that was incremental, was there a particular issue that arose over in a recent period that caused you to make this decision to do the replacement as opposed to

something that was more incremental?


I will let Guy answer that one.


So I will take a crack at that. In terms of was there anything in particular about the pipeline and the integrity of the pipeline that drove this decision? No. We always

take a long-term view to our integrity plans on Line 3 or any other pipeline and really what this resulted from was the heightened sensitivity by our shippers not just to

our ability to move crude but to the whole takeaway capacity situation out of Western Canada.

They want our reliability, they are counting on us to be there for our volumes for the next pipelines to layer on top of it and what they don't want to find is that we had

embarked on a multi-segment replacement program as Byron suggested the alternative was to find that to execute that program you have to keep taking the pipeline

down, starting it up, taking it down, starting it up. So the reliability of our throughput on that segment would be diminished.

So it is really an indication to us and to you and the community just how concerned producers are about the takeaway capacity. They are paying a substantial surcharge

on our system to ensure that our targeted throughput numbers can be met and that we have some flexibility to deal with some of these maintenance issues planned and

unplanned.


Just a quick one, it is Ted Durbin with Goldman Sachs. On Line 67, I think you had originally said you were going to bring that in two phases, that expansion. Should

we now read this as you are just going to do it all at once because I think you said you now expect the permit by the third quarter of 2015? Is that how we should read

that?


Correct.


John Edwards, Credit Suisse. Just if you could remind us on the Line 3 replacement, how old is that existing line? Just more broadly, what are you seeing with regard

to the price of steel for your pipe sensors -- there is presumably here an awful lot of steel on order?




20



So in terms of steel, I was looking at market pricing yesterday and it is around $1,350 a ton, and as I mentioned, we have a considerable savings relative to that market

price that is out there today. The Line 3 is 1960s vintage.

Sharon Lui - Wells Fargo Securities - Analyst

Sharon Lui, Wells Fargo. Given that I guess regulatory approval is one of the biggest risks. For a big project was the Line 3 replacement, how do you manage the

timeline between already securing I guess things on the supply chain and incurring costs versus getting regulatory approval which is expected by year-end?


So there has been some discussion in the press that we require to pursue a new presidential permit or an amended presidential permit but our view is that that permit

has been in place for several decades and enables us for maintenance purposes which this is, to replace the line.

So we don't see a requirement to pursue any lengthy federal regulatory reviews but rather those that we are used to in installing Clipper for example in 2010. So a

combination of the Corps of Engineers with whom we are very familiar as well as state regulators in Minnesota for example.

So we have been in Minnesota for example for 65 years. We understand the regulatory regimes of all of the states very well, of all of the local ordinances that are

required. For any project there are hundreds of permits required and we have a very large and experienced team who have secured those permits for us before and we

are confident that they will be able to do that again.

T.J. Schultz - RBC Capital Markets - Analyst

TJ Schultz with RBC. This may be for Guy or Mark but just on the Line 3 if you can kind of walk through -- I think this is put in your growth CapEx budget and

understanding the returns you expect, understanding the facility' surcharge mechanism but talk about the returns on that project and kind of vis-a-vis some of the cash

flow that you are losing otherwise?


I will take a quick crack at it and Mark can add to it if he wishes.

So the way that mechanism is working is that there is a surcharge that the industry has agreed to pay on every barrel that flows on our system both in Canada and in the

US. On the Lakehead system, the mechanics for collecting that surcharge is through the facility surcharge mechanism that we have had in place for many years and

have used on different projects. It does manifest on Lakehead as a cost of service surcharge to the tolls and I think the return on equity is in the low double-digit range.


The only other thing I would add to that is just it is traditional, you've got an equity rate base, debt rate base, equity component is 55% of the rate base, debt component

is 45%. The cost of debt is whatever EEP's cost of debt happens to be at the time and the return is, as Guy said, is pegged at the 10.75[%] plus tax so that gives you a

good rate of return on that investment.

Rob Vogel - Lucas Capital - Analyst

Good morning. Rob Vogel, Lucas Capital. You are increasing the pipeline size on Line 3 by 2 inches which gives you a fair amount more volume inside. Are you

expecting higher capacities and by how much?





21


It will be like for like capacity.


I think largely the increase of most of the line and the replacement of 36 goes to the fact that that is kind of the industry standard at many of the mills. I think to fully

replace the line in 34 inch service will be I'm assuming a substantial higher cost that would require a lot of retrofitting at a mill to get that. So the replacement will be

limited by the 34-inch capability of the replacement across the border.

Rob Vogel - Lucas Capital - Analyst

Just to clarify, you expect no increase in capacity?


I think what we have disclosed is we expect the capacity of the Line 3 system to get back to around 760,000 barrels a day in mixed service and as far as we can see for

now that is the expectation.

Jeff Birnbaum - UBS - Analyst

Jeff Birnbaum, UBS. Maybe asking those questions a slightly different way, on Line 3 and obviously you've got the surcharge, the cost of service mechanism but given

the capacity isn't expected to materially increase, are you accounting for maintenance CapEx going forward on that CapEx any differently than you would for existing

projects or other projects?


We expect for the new system, your maintenance CapEx would be down on that particular section of pipe but as far as the Line 3 project itself, it is incremental

earnings to cash flows to EEP so Line 3 is not a maintenance CapEx project.

Is there a nuance to your question that I missed?

Jeff Birnbaum - UBS - Analyst

Yes, I was just trying to clarify that effectively none of that 2.6 is actually dedicated toward maintenance?


Yes, it is all effectively, it is rate base and no component of it is treated as maintenance CapEx.


So, Sanjay, did we want to take a break?







22


Okay. So a 15-minute break and we will return with Greg Harper.

(break)



So someone whispered into my ear eight national titles.

Greg Harper - Enbridge Inc. - President, Gas Pipelines & Processing, Midcoast Energy Partners LP, Principal Executive Officer

Oh, that would be Kentucky. Yes, okay.


So it is my pleasure to introduce Greg Harper, President Gas Pipelines and Processing Enbridge Inc. and also Principal Executive Officer for Midcoast Energy Partners.


Thank you. It is great to be here, it is great to be with Enbridge, what a great team. And following Byron, it is pretty impressive the capital program that is being

deployed primarily on the liquid side right now, the crude side. But my ambition and Terry's is to deliver that type of capital program for the gas business going

forward, that is what we're going to be aspiring to do.

What did we bet, Maki, what is our bet? Wisconsin versus Kentucky is -- vodka, yes. It was going to be bourbon, but we don't do bourbon. So anyway, but I hope

everybody will be watching this weekend when Kentucky does beat Wisconsin and moves on to the final game.

So, I am here to talk about kind of the vision, the strategy and what is going on at MEP. And Terry is going to come up and get into some details. I know some folks had

some detailed questions around some of the different basins and projects we have going. So Terry will definitely address that in his key remarks.

Growth strategy -- we are looking to drop down post-IPO, our first drop-down midyear this year. We are looking for that to come from our parent. We have a very good

sponsor at EEP. The thing about, and you will see in the next slide and in your book, I'm not going to touch on it overkill here, but on the structure. But we have a

strong parent; we are very aligned in strategies.

We want to grow, we want to be a good facilitator of value for EEP and so, we can't just do that with just dropping down our current asset base. We want to grow this,

our current asset base. So we have to deliver on our distribution growth plan, we'll look at that in a second. We have some actionable opportunities in our market area,

we need to execute on those.

As a matter of fact, we've got to kind of earn to execute so we can step out of our footprint which is what I want to do in order to grow to the capacity I think we are

capable of. And my vision ties in with Enbridge's vision. Al's vision is for Enbridge to be the leading energy delivery Company in North America.

I want to be -- I want to have the leading natural gas and NGL business in North America. I mean it just fits. That is what we should aspire to be. And we do that by

being best in class. And best in class to me is when a customer or actually all stakeholders, not just customers. Customers first of course because we wanted shareholder

value to increase and we have to have more customers, we have to deliver for them.

But I want to be on the phone with a stakeholder when they have an issue or a question about the industry. I want them to pick up and call MEP. Talk to Terry, to talk to

me, we are the go to leader of the industry. To me that is best-in-class. So we want our customers to pick up the phone, call us when they are going into a new play, take

us with them.




23


You may know from my previous experience at Centerpoint we did that in the Bakken with Exxon. I want to do that at Midcoast, there is no reason why we can't. We

have great facilities we have a great team and we need to step out of our footprint.

I think Mark said it or maybe Guy did about the bottom block here. You have heard in a lot of past Enbridge meetings, past several years about safety is priority one.

Reliability is priority one. That is our license to operate. To me it is not just priority, it is our fundamental operation. We have to perform.

We can't go around losing customers' product or hurting people, that is not our business; we won't have customers if we do that. So it is not just priority one, it is a

fundamental part of our business and we should go to work every day, every employee should go to work knowing that that is just their job, is to operate safely and

reliably for customers and our communities that we work in.

The structure, as I said before, basically the big point here is that EEP as a vested interest in MEP and they want us to grow. The drop-down story is only a part of the

story. But the point is if we grow and are successful then Enbridge Energy Partners will be successful -- or more successful.

Right now we're at a 6.1% yield; it is good for you as an investor. I don't like that as a currency for me to go acquire things. I think it should be better and can be. As a

matter fact, if you take us down to that peer you would like it.

It if you are invested in us today, if we go down to a peer rate of 5.3% then our unit price should be at a current distribution should be around $23. So I mean that is

where we should be. We should aspire to be better than the industry average and that is what we want to do.

We have about another $3 billion of assets at the Midcoast operating level drop down. I think there are other assets; we'll talk about it in a minute, at the Enbridge Inc.

level that are promising and have potential as well.

We are a large scale player -- we are large-scale but limited to a region right now, to Texas. And I want to be a -- I want to diversify basins; I want to expand out into

and expand our scope and not just our scale but the scope and scale across the regions.

So what does Midcoast Energy Partners do? Well, it gives us -- obviously enhances our strategic focus. I am here to run the gas business; Midcoast is a big part of that

definitely in the US. And that is what we are going to do. And we have this great vehicle now that also gives us another currency, so it is not where I want the currency

to be it is still a good currency. And so we have enhanced access to capital. And obviously we have the growth with the drop downs from the parent, it is up there.

So, but there are other ways. In order to deliver a double-digit CAGR to you guys over time it is not just about drop downs, that is a good chunk of it but I want the

underlying assets to grow and that delivers part of that CAGR.

We have -- on our plan I think during the S1 that was out and the road show that the guys went on, they talked about $1 billion of projects that we need to go out and

secure between now and 2017. So that is about $200 million a year of projects, is that feasible? I think it is.

You will see in another slide in a second there's about $35 billion of forecasted potential over the next 20 years. So $200 million is not – it is basically within our

wheelhouse, we have been doing that. And it doesn't include acquisitions either. And I think in order to really grow and, again, get outside of our footprint we have to

probably do some acquisitions as well.

And then there is room for price -- for commodity recovery. But we will talk about commodity -- or exposure to commodities in a second.

Enbridge parent, we already talked about this, but I don't know if we have a lighter on this thing or not. But one thing I would point to on this slide is some things that

interest me that are at the Enbridge Inc. level would be Vector, is an asset up there, nice interstate pipeline in the US. The Offshore assets are being developed, we have

some great projects that are under contract, we'll start flowing gas and then eventually crude and some of them in 2015, 2016 timeframe.

So as we maybe finish the drops of the onshore assets, we will maybe have some nice offshore assets to drop into MEP over time. So -- and we know that Enbridge

parent is very interested in seeing this vehicle succeed. Again, if we succeed Enbridge Inc. succeeds as does Enbridge Energy Partners.

I'm going to cover high-level, and Terry is going to cover some micro level statistics around some of the production areas and NGLs. But obviously gas future is good.

By everybody's account it is going to be growing, the production cycle in the lower 48 is going to be growing. So we have a robust market.

We are in a very -- our assets right now at MEP are very well situated for the market side as well. It is definitely with power generation, but more so from the industrial

side. And from ethane crackers to commercial utilization for gas and the Gulf Coast area. So very well situated in the Gulf Coast.




24


There are some other areas you would like to play in where power generation will be growing, Southeast will be a great area and the Northeast, obviously growth in

those areas for markets.

This slide is kind of interesting because it takes a look -- we have a Canadian midstream business too that I manage. But the Gulf Coast, relative to LNG makes very

good economic sense not just to here, but obviously to Asia as well. And we are very well-positioned coming out of the Haynesville as well as the Barnett to get gas to

the Gulf Coast. So, I like our position with our current asset mix relative to the potential for LNG exports.

This is the slide I was referring to earlier. And it just got reaffirmed by INGAA Foundation; NICF re-released or revised their study from 2011 that reaffirmed these

numbers around $30 billion a year over the next 20 years. And they also looked at all of North America too, but what they did this time that's not in this particular study

is they looked at compression and processing capacity as well.

So $30 billion plus a year, I think there is potential. We should be out there going after and capturing our fair share of that potential of infrastructure. And that is what

Terry and his team and John in the back -- that is what they're going to be charged with.

Now a high-level view of where gas is flowing. You all know that with the shale plays the map is all over the place relative to pricing. I was chatting with think with

David earlier during the break we talk about pricing that it was only 100 miles that separated the highest priced gas market and the lowest priced gas markets in January

and early February, that was Boston versus Leidy, I mean 100 miles.

So, a lot of things going on obviously in the Northeast with the Marcellus and Utica. Obviously we don't have a footprint there yet. That will be an area where we would

have to go in and maybe acquire to get a footprint or a toehold and do it at a reasonable type number.

But I would like to play up in the Northeast and that is -- I think there will be some great opportunities in the Northeast as I think some producers re-rationalize their

midstream assets and other midstream companies re-rationalize what they are trying to do and where they are trying to play.

High level on our current asset mix, we have about 2.5 Bcf a day of gathered volumes, we have nearly 2 Bcf -- 2.3 Bcf a day of capacity for processing. Terry is going

to look at each of these areas, but I've got the Anadarko area, the North Texas system and the East Texas systems.

We've got some new areas that are around us on the Cline Shale play that is slowly developing. I would say the Eaglebine has a little more gravity to it for us. And I

think the producer is a little more excited about the Eaglebine which is right off our systems, both our gathering system as well as would be able to access the Texas

Express pipeline, which is our joint venture.

So, we are well-positioned where we currently are, but we really need to step out of this footprint. I would like to expand outside these basins into other basins. I would

like -- there is nothing wrong with dry gas. The right price markets; it is going to flow. We do need to get exposed obviously to more wet gas areas.

But having a balance portfolio as we go forward on our supply basins, the type of gases we are bringing in crude drops, liquids prices drop. I can remember when I was

at Spectra -- it could have been in the Duke days not too long ago, 10 years ago, when liquids prices were not that good and that business was not doing that good at

DCP.

So I would like to have a balanced portfolio of what we're bringing into our systems what we're able to gather going forward. So, we need to leverage our existing asset

base, expand our processing capacity. This is what we need to do on our core system today. Pursue accretive transactions. I think they are out there.

Use our currency -- while it is not as good as I would like it to be it is still a good currency for sure. And it can be better. Again, as we deliver on our numbers, our

currency will improve and it gives a better chance of capturing some acquisitions just like we want it. Obviously you saw the shifting basins. I think there are going to

be some big pipe opportunities out there; big pipe opportunities to partner into if not do ourselves.

So, priorities -- obviously we need to execute on our first drop-down, it needs to be at a fair value, I think our Board is going to, obviously the special committee will

determine that. But I think a fair value; a good value is going to benefit everybody on that first drop-down. It is going to be all debt on the first one.

We obviously need to aggressively pursue and secure organic growth in our footprint. We need to execute on the assets we have, we need to get our processing plants

full. We need to optimize the processing plants, make sure that they are full with the richest gas that is on our systems.




25


We need to rationalize our existing portfolio; we have the opportunity to shed some assets on the offshore side. Obviously not relative to MEP, but we did just get rid of

the Stingray assets. So we need to look at our other systems. We did get rid of some -- about 700 miles of pipe in North Texas that was only moving like 7 million a

day.

Somebody else valued it more, it was also -- it was our largest contributor to lost and unaccounted for gas, about 20% of our lost and unaccounted for gas was coming

from that system. So, we just need to look at our assets, rationalize what they are doing. Are they deployed and the right place, if we have skid mounted assets,

processing or treating can we move them to get a first-mover advantage.

We had the logistics and marketing business which Terry is going to talk about more during his talk. From my perspective, it is currently an optimization vehicle and I

would really like it to be a market maker and not only use that in the trading sense. But more I want to use logistics and marketing as a vehicle to bring more gathered

volumes, more gathering opportunities, more physical infrastructure opportunities too.

They should be going out to the wells. Their trucking needs to turn into pipe over time and we need to bring -- convert those trucking opportunities into infrastructure --

pipe infrastructure deals. So, that is what I will be looking for Drew and Janet's -- their teams under Terry's leadership.

And of course manage costs. If we are going to have a period of lower volumes, then we need to make sure that our costs are commensurate with a lower volume

scenario. So, we are challenging our teams and our operating teams, Terry and his team, to make sure that our operating costs are in line with the volumes we are

flowing.

So, key takeaways here. We are going to deliver on our S1, our distributable -- our forecast and distributable cash flow; that is a must, it is a priority. We have to hit the

S1. I think another thing David said is we don't want to overpromise and undo deliver, we want to deliver on your expectations and meet your expectations in what we

said we would do, if not exceed those expectations.

We have got to strengthen our underlying business, as I just mentioned before. We truly have to physically optimize our assets, rationalize our assets and redeploy

where necessary what we are doing.

And then we have the great fundamental of the gas futures and the future production not just in our footprint, outside of our footprint is going to take us places. We need

to make sure we are opportunistic, where this vehicle gives us an opportunity to be when I say more aggressive, I think more opportunistic in the field where actually

we will be viewed as a buyer as opposed to just a looker.

And so, I'm not going to get crazy with the currency, we are just going to go out and be more actionable I think of what we have the opportunity to do. And the great

thing about our Board at MEP and our ability to move, I think, quicker is because we have a Board that is made up of gas industry peers.

So I think that's good for you all, that you know that your independent directors are very knowledgeable of the industry, we can bring them deals that they will be able

to understand more quickly I think and execute upon. So that is a great foundation.

And again we are going to -- we have to operate safely and reliably, that is our license to do business. So that's a fundamental. With that I will take your questions on --.



Yes. Hang on one sec.


Mark Reichman at Simmons. Greg, I was just curious, how do you think about balancing your growth? In other words increasing your ownership of the existing assets

versus achieving your goals of diversification and growing outside your footprint? And what do you have in mind in terms of a timeframe on the drop downs from

EEP?




26



Yes. Well, I think the first drop-down, look, we have already -- we promised a drop-down initially, we are going to deliver on that. I think to truly bring value to

Enbridge Energy Partners, we have to get our legs under us on the current assets and deliver on those numbers and grow. So that would be my next -- the second asset

drop will have to come when we start delivering numbers to you guys I think.

One thing that didn't show up there -- and I'm surprised it is not on my graph, maybe it is on Terry's -- but we have like 40% or 50% of our business is fee-based, which

sounds good. And I think another 30% or 40% is hedged. Our fee-based though is volume exposed.

And one of our charges to Terry and John and his team is we obviously want to grow our pie, grow that revenue pie. But I want to grow it with more secured volumes.

And if I can actually get assets dropped into the vehicle that have more certainty may be an interstate pipe type quality that would be great.

But more importantly our gathering business needs to have more of that fundamental type secured guaranteed type business. The more we have that foundation then the

more commodity exposed. Again, that is another balanced portfolio component is our balance of contracting.

So, supply balance, basin balance and then I think truly contract balance is what we will be shooting for going forward. I think we will deliver better results for you

guys.

Jerren Holder - Goldman Sachs - Analyst

Jerren Holder from Goldman Sachs. Can you comment a bit more about the Enbridge gas assets that potentially might be available for MEP I guess later down the line?


Sure. Yes. I think the offshore assets are about $1 billion of book value. Is that correct, Steve? And what is the book value on the Vector? $400 million? Yes, $400

million book value. So those would be kind of the two things I see out there.

You know, Alliance is out there, Aux Sable is out there, but I really -- those could be some other opportunities for Enbridge Inc. to take advantage of on the Canadian

side just simply the way those are structured I would say.

Jerren Holder - Goldman Sachs - Analyst

Greg, one quick question on the debt side. Do you expect to be investment grade and what kind of leverage metrics do you anticipate for the Company?


I think we went out saying we want to be around three -- three times. If you do -- again this is that -- make sure -- I know we had this discussion at some of our one on

one sessions a couple of weeks ago with some of you folks that came through at the Morgan Stanley conference.

Again, our metrics are off of Midcoast's Operating level, not just looking at MEP. So make sure when you look at our debt numbers you are looking at the complete

Midcoast operating numbers. So even with this first drop that still gives around I think two -- when I do the math we did the average what we have been saying around

yes 2.9, yes, 2.8, 2.9.


(Inaudible - microphone inaccessible).





27


Yes, still investment grade, or that is what we're shooting for for sure.


It is Noah Lerner. Just was wondering if you could talk a little bit about each of the basins. I mean you talked about the fee-based revenue still carries volumetric risk.

Just curious if you could talk about what you are seeing in each of the basins and what you as an organization are specifically doing or planning to do to try to capture

some additional volume so that you don't effectively have a depleting asset.


Yes. So -- and Terry will definitely cover this in more detail. I will give you my 30,000 foot level. Anadarko Basin is very competitive. Trying to capture guaranteed

returns or volume commitments is very tough in that market area. So, we have to kill and eat every day out in that market area.

The Haynesville, East Texas area a little bit different. Production profiles are a little more accelerated and we are able to capture some deals, and if you look at our

margins you will see they may be a little bit thinner in that area but we have more certainty around those cash flows in the East Texas basin.

North Texas same, low delivery volumes on those wells. Again, it is kind of a lot of historical capacity there, and I don't know if there is a lot of room for fee-based

there. Demand-charge fee based.

That is why I would love to get out, get to the Utica, get to the Marcellus, Bakken would be a great -- I brought this up at a Board meeting. You know when I look at

our map and the big map I showed you a second ago Enbridge is all over Bakken; they are the king of the Bakken.

We need to be playing in the Bakken for gas gathering as it develops and processing. But also, even crude gathering and the little lines of crude gathering getting them

to the big pipes that Guy runs would be a great opportunity for us and you can capture those types of the volume deals. Volume and demand type oriented deals.


It's Yves Siegel with Neuberger. In terms of looking at Vector as a potential drop-down, would you have to exhaust the drop-downs? Why don't you just -- the question

is just in terms of sequencing. Could you see Vector being drop-down sooner rather than later as opposed to exhausting the drop downs from EEP?


Yes, these are things that Mark and I just started chatting about. So, I would see no reason why you couldn't drop in something from Inc. before you depleted all of

your -- all of your Midcoast operating. It just depends again; EEP needs some cash so we are doing that for EEP. If the parent needs cash or it makes sense. If it makes

sense to me I think, again, the stronger Midcoast Energy Partners the better valuation we will get on other drops.

So, I think we just need to look at our plan, what is going to add the best value to truly, truly increase our currency. And so what is the strategic timing of those. I think I

want to do what is going to be best that is going to really give me the best multiple when it is time to go out and get something outside of our parent or parents.

But there is no -- I don't think there is any magic that says you can't do one before the other. All right. With that I am going to turn it over to Terry to do all of the heavy

lifting here.

Terrance McGill - Midcoast Energy Partners - President

You mentioned, John, a couple people that came with because I need more help than the other speakers. So, I had to bring people. John Loiacono in the back is Vice

President of our asset team commercial activity, and Kerry Puckett who is our Vice President of Engineering and Operations. So, I may toss some of the hard questions

that Yves asks to those guys in the back.




28


Let's see. So, Greg did a great job covering the macro, delved a little bit into some of the micro of it all. But I want to go into -- maybe peel it back one more layer, start

a little bit with my view, at least our view of the industry fundamentals and then on our particular asset bases what is driving -- what are the engines driving each one of

those asset groups.

So, there will be a couple of things you will take out of this whole presentation all day today. Common themes from Liquids and Major Projects and everyone. But it is

always how do we enhance -- continue to enhance the profitability of the assets that we currently have before you go marching off to the new areas to make sure you are

doing everything you can with the assets that you currently have.

So, we are in Texas, we do like the three basins that we are in, quite a mixture of formations and productivity in the areas we are. But, as Greg said, we have always had

a hankering to go to some of the other areas and do the same -- bring the expertise that we have into those other basins.

Leverage -- of course I talked about the asset base. One of the key things is the enhanced access to capital. As we talked about this on the road show and you heard

about this on the call, we are able to go out and get gas capital for gas projects.

Within EEP the dollars went to the crude oil, not all of them, and we are obviously building a lot of stuff in gas, but the marginal dollar went to the crude oil pipeline

business, which it should have. But this gives that enhanced access to capital which allows us to go out and look at things that are going to be harder to do all buried

within the EEP structure.

And you mentioned the first drop-down this year and saving gas. The safety and reliability. The oil side has leaks. We have eight stress lines, we have natural gas, we

have populated areas, so the safety and reliability of our assets is extremely important to us, to Enbridge, to Midcoast.

So there is a strong focus on that and the group is working on that. Kerry's group works on that. I think they get up every morning and think about how can they operate

this safely and reliably and let all of the employees get home safely at the end of the day.

One of my sayings, and apparently I have a few, is not all MCF's are created equal. And I see this when we talk in averages, or volumes, we mentioned 2.5 Bcf. Yes,

well not all of the MCF's are created equal.

You look at our areas and the producers when we are -- it is interesting, we'll get gas behind central points but we also get a lot of wells connected to it. So we get a

little peek into how good these producers really are when they are drilling. We have type curves and we do all kinds of geology and we have all kinds of work we do on

this.

But there is a noticeable difference in the multiple formations within a particular field, where that producer is aiming for. Whether they are in the sweet spot or just

missed it. And we will see them a mile apart the skill sets of the rig crews, some of them that either they don't have a B team or an A team or some of them just aren't as

good at it as others, and it is amazing.

So, when I look at this and I say all the MCFs are not created equal, they are not. The richness of the gas, where they are, how good the producer is, all these things

factor in.

When you look at -- up here, just dry gas we did not take the basis differentials for the gas in East Texas, but you look at the Cotton Valley which is a richer stream, you

look at the Anadarko, Granite Wash versus -- and you see they are very profitable wells to drill on our system.

And they will talk about this in a second, well, yes, but everybody likes the Eagle Ford or Marcellus, not all producers go there. Not all producers have acreage there.

There are some producers that only have Granite Wash, there are small producers that only deal in the Barnett Shale, and they are going to drill their two, three, four

wells a year and that is the way it goes. That is just what they do.

So we'll talk about the growth, this is a collection of the experts, which means there is a little hit of variability like economists, right and they are all -- and I don't know

what that -- the Haynesville looks like a snake that swallowed a rat. But it is probably, the answer is in there somewhere.

But you see the upper -- a trend going up. The Barnett -- that is not fair, this is how it works. I think you have got 11,000 wells in the flat part of the curves. I think the

science has been perfected, the acreage is all held, there is more than enough take away capacity, Dallas-Fort Worth, the market is sitting right there. I think if you want

to see the Barnett grow you just follow the price curves of the natural gas. That is really what moves it.

Now there is an area, Marble Falls, there is some areas where they are going after just -- really just oil and you will get associated gas that is going to be small volume

but seven, eight GPM gas. But the Barnett as an example, it is just follow the price curve.




29


The other areas, Anadarko we still have drilling out there. And of course Haynesville, there are producers that make money at $4.50. They are very good at it. Other

guys that need $5 or $5.50 they don't have the best acreage and maybe they are not quite as good at it.

One of the key things, one of the big drivers for us of course is NGLs. And the NGL production, the industry -- the producers have done to NGL prices kind of what

they did to gas prices, you bring in the -- your productivity got very good, you found new fields and we are awash in natural gas. You see the resulting response in

prices.

They moved to -- and we are very much a copycat industry, by the way. One guy does it, then they all do it and everybody is fracturing and everybody is doing

hydraulic drilling and we are awash in NGLs. We have got more NGLs than we had market; we got a little out of sync I think with the market.

The petrochems are being built, they have been cited. I think Byron mentioned regulatory concerns. Yes, it is tough getting air permits for the next fractionator at Mont

Belvieu. It is tough getting permits for the next petrochem facility down at Freeport.

You will get them, but it does take a lot longer than it used to. And your ability to just get your permit and off you go, isn't quite there. So you see petrochemical

complexes coming online probably 2017, 2018 into 2019 and you will see the demand come up. But what is going to drive it is going to be exports. We need the

exports.

And with Enterprise and Targa doing at Mont Belvieu -- trying to remember, I think 420,000, 430,000 barrels a day we had to shut the channel down because the

accident there in the fog. But -- and that is continuing to grow.

This just shows you the gray area is the traditional NGL supply from your traditional basins and you can see the growth coming from the shale plays. And all of it

requires infrastructure. We are building in East Texas, they've been producing oil and gas of East Texas since, I don't know, 1925, something like that, we are building

new infrastructure. All of these areas still building.

And I think Greg had mentioned a huge -- I don't know, $400 billion of infrastructure acquired in the United States over the next 10 years to take advantage of the

opportunities we have. And it is going to take more than one company to do that. We'll get our fair share of that.

Demand outlook, again, it's going to be driven by the -- it is amazing, it is kind of interesting, you've got it in your book of what all these things are used for. And you

see ethane is pretty basic. Right now we are rejecting ethane, putting it in the gas stream, which shows the growth in gas.

Everybody is still -- it is still a lifting mechanism to get the NGLs and the condensates out of the ground. So you see the growth in gas. You also see the growth from

rejected ethane showing up in the gas stream. But we do see demand or supply growing for that -- or excuse me, demand growing for that and the export is going to be

very, very important.

I don't know how they are going to get the ethane exported, they are going to blend it a little bit, but you are looking at the LNG, not just methane but a lot of things

have to happen to get the LNG out.

And you are employee of the year. John, you are in second place, buddy. I needed a Dr Pepper, this is really tough to do up here and, excuse me, oh, this is good. Yes,

10, two and four. Where was I? Okay.

Greg showed you this map. Let me take it down to a little bit deeper what we are looking at. Of course starting left to right let's go up there to the Anadarko system. Of

course the Ajax processing plant came on stream, when was that -- November, somewhere in late last year?

We have already produced -- actually I was watching today, over 1 million barrels have come through there, we are running 10,000 barrels a day. So we are getting the

kinks worked out of it. The reason you start up a new plant is to find out what doesn't work. And you go through that punch list, and I think it is getting very, very

smooth operations right now.

Texas Express, Ajax only goes to Texas Express, it is the only outlet for Ajax is Texas Express. That came online. Again, you get the start up bugs worked out,

Enterprise built that and operates that, we own 35% of that. That is up and running, bringing more product out to Belvieu.

So we definitely -- it is part of I think what Greg was talking about. It is the fee-based, but I know the fee-- I've also got secured contracts on it. So it is just a true take

or pay and everybody likes to have a base load of that I think in your company.




30


Moving to North Texas, I mentioned that. They kind of skipped the condensate, kind of the Granite Wash and just really went to oil with associated gas. Very small

volume, extremely rich, our plants -- Springtown and Weatherford being the big plants up there are running at capacity. So we are getting what we want out of that area.

Beckville, Byron mentioned that under construction. If Byron would hurry up, and we had this plant Monday, which I know -- I'm sure you are trying very hard, Byron

-- it would be full. We are bypassing processable gas today. What we're trying to do on a smaller scale certainly than the LP group does is getting the right to batches to

the right refiners at the right time.

We are trying to get the richest gas to the most efficient plants and right now it is probably 1.6, 1.7 GPM gas we are able to blend out with dry gas and bypass the plant.

And try to get the 3 -- Cotton Valley, 3.0- 3.2 GPM gas into that -- into our facilities.

So, our facilities in East Texas right now are running at capacity and the plants in -- like I say, Beckville will open -- basically will open full. So, very excited about that

one. That will be in January of 2015 I believe. Right? Yes, okay.

Logistics and Marketing -- let me talk about Logistics and Marketing. I will go into a little detail later. It is, it's the optimizers. John Loiacono's group get the gas, get

the plants, get the product. And then we turn it over for hedging, storage, marketing, transportation.

Our product, because we are long commodities every morning and product we buy from other producers from the producers, especially the smaller ones who do not

have the wherewithal of their own marketing groups will do that for them. And Janet Coy in the gas marketing get it to market, get it placed and then optimize it around

during the day. Drew Laughlin in the ELTM, our condensates, crude oils, NGLs -- store it, frac it, all the things one has to do to get it to market.

We got too big to just dump it off into a pricing point, to just throw it into Belvieu and say, here, I hope it works out okay. Not with 90,000 to 100,000 barrels, we have

to manage our own destiny to a degree. And Texas Express, as an example, that as we work down the value chain, right. Ajax plant owned part of Texas Express, have

long-term contracts for fractionation, have storage, trucks, rail, barges, and I can move it to market. So that NGL, we have got the whole chain.

We are seeing -- start bringing it in a little more recent, we are seeing an uptick in the permitting. Now permitting is an indicator, it is not a guarantee that anybody is

going to drill. But you have got to start somewhere, and we do see the uptick in the permitting. Fort Worth basin, again, smaller wells but you are seeing growth there.

And East Texas. A little bit in the Anadarko, but East Texas is with the Eaglebine, with the Cotton Valley, it is once again getting to be a hot area.

So, going into a little more detail. Let's peel it down one more level. The Anadarko system, sitting up there across the -- we'll call it the TexOk -- the Texas Oklahoma

Panhandle's. The acquisition at Elk City is on the Oklahoma side and then our traditional kind of Anadarko area over on the Texas side.

There is still activity. Some of the bigger players can move to the Eagle Ford and have, they come back -- this area had just some lousy weather so we are seeing an

uptick as people are coming back in. Again, it is very economic to drill here.

We have takeaway, we have eight outlets for the natural gas, we have two outlets for the NGLs with at least Ajax going to Texas Express, the balance going to another

third-party transporter. Ultimately, those barrels will move into Texas Express as those contracts expire. So we're very happy with the Anadarko system.

We have a rail facility in Pampa, Texas where we are able to rail stabilized condensates. We are doing upgrades to our Ajax plant on the stabilizers, so we are able to

take -- some off spec and unstabilized condensates, straighten that out, take it right over to Pampa, load it onto rail where we've actually sent carloads up to Edmonton

to use as diluent. We have sent them over to Mississippi.

So, it is getting to be kind of a full service -- and I should mention we do have high, low, and medium pressure systems. So we really can be a full-service provider to

the producers in that area. And when I show you the type curves, you will see the producers can come on. And they like the high-pressure system.

Fine, they've got plenty of pressure in the well. But as that well matures, they need to move down and we are able to, and very often just move them to a different line

where they get lower pressures and they are able to get more out of that well than constantly bucking the high-pressure. Or trying -- putting in their own compression.

East Texas, several neighborhoods that live in the same city. We call it East Texas, geographically it is very a big area. But inside of East Texas from the sour treating

facilities we have on the north end, the Haynesville kind of on the east side where we have the Louisiana border, Cotton Valley is also over there. We will see Eaglebine

will be down kind of the South in the green.

And so, we get a little bit -- there are several formations within the field. We have kind of particular areas that are predominantly one style of drilling or one type of gas

than another. But they do move around quite a bit. All the rigs have wheels, it doesn't take them long to get to the other side and off they go into another formation.




31


The Eaglebine -- as Greg mentioned, the Eaglebine we are very excited about. It is very close. The Cline Shale off in the kind of edge of the Permian Basin, we have got

a lot of acreage dedicated to us. But I think Mr. Loiacono would say not all rock is created equal either. It takes a while for the science to be perfected on any shale or

any tight gas or tight sand formation before you will see the -- really improvements.

So, it does take a while for the Marcellus, and I think they are going through the learning curve on the Utica to be honest. I don't think the science is totally perfected

there.

North Texas, I mentioned that. We do have our stabilizer at Springtown. So, what we're forced to do is we are forced to truck our condensates from the Anadarko, we

take it down to Springtown, stabilize it, off it goes to market with an upgrade. And buried inside of the $200 million a year, $250 million a year that Greg mentioned are

secured projects.

Unlike the liquids group, we don't have -- very often we don't have a big one with a name. And there are two or three of them fills it up and everybody gets to watch

that. I think on average, Kerry may correct me, we have probably 700 open AFE's at any given point in the gas side ranging from big like an Ajax or a Beckville all the

way down to just well connects.

But in the middle compression projects, putting jumpers in, more efficiently operating the system, upgrading some of the older plants to be able to handle the richer gas,

not all of it can handle the Cotton Valley, it wasn't designed for that. We will upgrade the plants, we are able to extract more liquids out of those, so there is a lot of

projects buried in there.

The stabilizer in Springtown is one of those projects. It is a great deal. And actually, I will tell you just a quick story, it is a great example of employees and the

dedication we have. The guys were sitting in the break room, they were watching that and they were talking about the condensate and we were talking about we have

got to haul it all the way over to somebody else's stabilizer.

And one of the guys looked up at one of the towers that was unused, we bought this from Canterra I guess several years ago. And said I wonder if we can make a

stabilizer out of that? Literally, they were looking around. So they got an engineer and he said, yep, they can and we probably -- we did a 4,000 barrel stabilizer for

what, Kerry, $1 million?

But the guys said there has just got to be something we can do; there has got to be something more than what we are doing with it now. And that has become -- it has

become quite a traffic jam in Springtown, Texas when all the trucks are coming in now for this. But it has been a great business and an example of the creativity of the

employees.

I mentioned Texas Express, our partners being DCP, Anadarko or Western Gas I guess now -- or did they move to Western Gas? I think they did. Okay, they drop it in

there. And then Enterprise. Enterprise being the constructor and the operator. The volumes are ramping up there.

One of the things we are waiting on -- it comes out of Skellytown, Texas up in the Panhandle and it is fed third-party wise, if you think it that way, from three arrows

from the south, it is from Hobbs and the Enterprise line, from the north it is from Conway and then one coming in pointed to the southeast is the Front Range Pipeline

that just came on a month ago, a month and a half ago I think, started delivering with a lot of Rockies production coming in that way.

Our plants, we are doing the plants connected to test six express, everything else comes in at Skellytown. And right now Ajax and Anadarko is in Texas Express. All the

other plants are not, they will as the contracts expire. In North Texas all the plants are connected, except Springtown. It is on a long-term contract to a third-party, so

they will transfer over 2018, 2019, somewhere in there.

So, it is a great project. It is again what Greg is looking for, we are all looking for, to build that base. It is fee-based but there is an obligation behind it. You haven't just

decided how much you are going to get and then take the volume risk, there is an obligation behind it.

I mentioned some of the volume trends. What we are seeing in our areas is a richening of the gas stream. As you would imagine, price is still better than dry gas. These

are the type curves we look at trying to determine this producer, when he gives us his drilling plans.

Producers by nature are a very optimistic bunch. Everybody has got the best wells, everybody is going to have -- do a great, great job. We use the type curves with our

group and outside experts try to get all of that information, figure out what is the likely curve that this well would follow.

But you see I think probably -- go over on the far right there with Anadarko. You see a typical Granite Wash well, which are big wells coming in, it's a lot of gas and

they have been replaced by the Hogshooter. The Hogshooter has got a much lower initial production rate. It is much richer gas though, it is in the 6 GPM range.




32


If you look at the Cotton Valley over in Haynesville, Haynesville has got hardly anything, Cotton Valley is that 3.2. So you get a lower volume, richer stream.

So, you will see in some of our numbers where you might see a decline in the absolute volume, but you see the NGLs remain flat or once we can do expansions you will

see the NGLs growing. That is just a manifesting of this richer -- richening up of the gas stream. So again, not all Mcfs are created equal. The guys are tired of hearing

me say that.

When we look at the business opportunities and the things that we have, the growth opportunities, how do we get more of the rich gas, how do we get the rich gas to the

right plants? How do we protect our house, in effect? How do we protect the areas we are in? How do we provide the services to the producers so they are not wooed

with the Siren's call of some other third rate MLPs trying to get their business.

You know who they are, I am not going to mention any names, but you know who they are.

And all those things are very important and then we have got the skill sets, we have got the creative people, we have got the enhanced access to capital. How do we then

take that and move into the other areas? Whether it be the Bakken, as Greg mentioned, Marcellus, Utica, Eagle Ford, there's plenty of them.

It's getting the house in order, making sure everything is running right, using the better currency, not competing with the crude oil systems at EEP and then growing the

gas side of it.

When we look at -- we don't put names on a lot of them, but we just -- a $14 million NGL line over to Panola as an example, $3.5 million for a stabilizer at Ajax, all

these things, great multiples and add a tremendous amount of advantage. But it constantly is -- we have got to swim deep. You have got to keep moving, got to keep

changing, got to keep updating your facilities. Optimizing systems is an everyday business, the guys are doing that constantly. Every -- ethane rejection is a daily

decision.

Logistics and Marketing. We use them as advanced scouts. I mean they optimize -- again, the commodity that we wake up every morning with, we're long commodity,

and get that to market. We make -- I will tell you this, what really annoys them, we make much more money on the processing and gathering fees than we do on

transportation of gas or the marketing -- just the pure marketing of NGLs.

So, their number one job is to get Midcoast Energy Partners product to market, make sure it is moving, make sure we are not the village idiot in the prices, but don't

play Wild, Wild West and always try to get the best -- make sure it moves to market. Because that enhances the reliability in the gathering systems and that is where the

bigger part of the margin is made.

But we use them as advanced scouts. It is a lot easier to go into the Marcellus with trucks, with rail, with marketing and get the lay of the land, get that peek over the

horizon. Who are those players, how much product do they have. And like I say, all deals to the extent possible followed by pipe. Followed by long-term commitments.

And the intelligence your marketing group brings you, again that peek over the horizon, what is going on, leads to opportunities. And we need to move more from the

optimizer to that advanced scout and get up into those areas.

I talked about the organic projects, of course and I mentioned the Ajax, Texas Express, they're up and running, Beckville is under construction. What do we do with the

other $250 million a year, or the $1 billion over the period through 2017? How to extend the reach of what we have, how do we get into the other areas? Are there

growth areas for us? Is condensate treating ,especially the off spec stuff?

Everybody can handle the nice, sweet, clear put it in your car tomorrow kind of thing. But the big margin is the ability to take the off spec and treat that and get it to that

point. I mean we are measuring it in dollars not in dimes on the margin upgrades, being able to provide that service.

And of course rail terminals in some of the -- the [big] Petal, Mississippi is becoming more of a hub. It is not going to beat the Belvieu's and all of that, but it is kind of

the doorway into the southeast. There is storage there, there are salt dome facilities there. We have rail facilities there, we are purchasing some other -- not cars but

access to lands to handle more rail.

But Petal is -- if you had propane in Petal this winter you were making a lot of money. We had propane in Petal, so we were very happy about that.

You have heard from Guy -- Guy and Greg and everyone on safety and operational reliability. We have different assets, they are gas-based, NGLs, we have one 40-mile

crude oil line which we just steal all the good ideas from the North Dakota boys because it is about the same size, so we didn't have to invent anything new on that. So

that was great.




33


But how do we manage our systems, and especially our H2S systems? I think we are probably close to if not an industry leader in how we monitor, how we do the

assessments, where we put our valve, how we check for leaks, all the things we do. And some of our pipe is also old. Greg mentioned the 700 miles that we sold -- oh,

gave away because it was 20% of our leaks last year.

At some point, you know what, at Enbridge I know what the requirements are, I know what compliance is. But in some areas we just have a higher level of tolerance --

or a higher level of standards I guess -- for how we operate. That is just the way it is going to be. That is the way Enbridge is.

So takeaways going into a dazzling presentation by Steve Neyland -- he has been practicing this, so everybody be very kind to him -- is enhancing the profitability.

Again, operate what we have to the best of our abilities, to the best of the assets that we have. Leverage it and move into other areas.

We like the -- as investors our access to capital. But as investors you're at a 6.1%, 6% yield, something like that. It is a great entry point in the NGL pricing curve. And

we have the NGLs. So it is -- I think it is going to be strong fundamentals and very good going forward.

So with that let's go to Q&A. If anybody has anything, it is such a shy group. Noah, loved your movie, by the way.



And believe it or not, I don't get any royalties on it. In an effort to beat the dead horse, going through all the different basins in the charts that were in the presentation,

there are numerous rigs -- several rigs to numerous rigs, I think one basin actually had double digits, in the various basins on your dedicated acreage.


Yes.


Could you comment a little bit on basically what you know of the drilling plans for those rigs and the various producers that are behind them and your typical type

curve in those basins? Getting back to my earlier question to Greg regarding maintenance volumes, taking into account that you might be switching to richer gases that

might be more profitable even though you have less or smaller volumes.

Just trying to get a sense of, with the activity that you do see and know about, what you think volumes might be. Are those type curves on the new wells enough to

offset the depletion looking into the balance of 2014?


The producers, John Loiacono and Kerry Puckett went up to visit a producer I guess this last week. And you are talking to field guys and it is like they work for a

different company than the marketing guys as to where they are going to drill, what they're going to have, how big the wells are, whether they are excited or not excited,

it is amazing.

The producers -- I know one group, I think it was Devon actually, that the marketing guys found out about the reduction in their capital when they were listening to the

analysts call from their CEO. And so, it is tough.

We get the drilling plans, we talk to all of our producers, we get their plans, we know their budgets. Their plans are pretty good for probably the first six months, John,

and then they start to get a little shaky beyond that because I'm not sure how confident they are. They will just pack up and go to the Eagle Ford.

You take Devon as an example when they bought -- I don't know how much they paid, quite a bit, for the GeoSouthern, GeoSouth acreage down in Eagle Ford. Yes, it

was all rigs going to the Eagle Ford. But not everybody has that ability. Not everybody has Eagle Ford acreage, not everybody is very good at it.




34


So, we see a lot of activity, some names, SM Energy, EOG is everywhere, Chesapeake, Sanguine, Sampson, they are all drilling some level or another.

It is generally the smaller guys, the mom-and-pop's kind of groups in North Texas, they will do there two wells a year every year, regardless of price, that is just what

they do. The Haynesville has been very mobile, people have moved out of the Haynesville or those who have stayed have just completed into a different formation.

The Haynesville is still there, they can always go back and get it, and they just do the Travis Lime -- James Lime, Travis Peak, Cotton Valley formations. So hope some

of that helped, Noah.

Yves, what, did you feel bad for me because Byron got all the cool questions?


Just two quick ones. One is as the contracts expire on the NGL pipeline, is there any uplift for you as you migrate those volumes to Texas Express or do you just

benefit from your ownership of Texas Express?


Just really from our ownership percentage.


And then the second question is as it relates to fractionation capacity, I think you said you have about 100,000 barrels a day. How much of that are you contractually

obligated to take? And the second half of that question is, as you -- you look confused. I meant do you have take or pay on that 100,000 barrels a day or not?


Is it okay to disclose the amount of fractionation we have in a contract?

Unidentified Company Representative



Should we? Am I breaking some rule? I think it is, John, about 70,000 barrels which is a take or pay of frac capacity. And we are -- we're actually probably using --

there is probably a little bit of it that we are not using and that is really just the difference in the rejection of ethane.


So that is the second half of that question which says -- which would suggest that as you try to go after incremental business you are able to offer fractionation

capacity?


Yes.





35


So that is not a hindrance to you to attract more business?


No, it is very helpful. Again, you are talking to a producer -- some of the producers like to put their own gathering system in. It's oh, I am going to build a plant. Fine,

you contractors, they'll go build a plant. It is what do you do with your product now? How are you going to transport it? Oh, I can get it to Belvieu.

Really? What are you going to do then? Where are you going to get your fractionation? How are you going to market it, all these different things that not all of them

have completely worked out the entire value chain. But having frac capacity, having the ability to dispose of the product post fracking -- fractionation is critical.

We can make all of that happen. Or to a producer make all of their problems go away. Steve, you're ready? I'm not seeing anymore, we will be hanging around. Let me

introduce Steve Neyland.


Steve Neyland - Enbridge Energy Partners - Vice President, Finance

Good morning. Glad to be here today. Steve Neyland, Vice President of Finance for Enbridge Energy Partners as well as Midcoast Energy Partners. I would like to

introduce Jonathan Rose, Jonathan is our Treasurer there at the back and we are excited to have him on our team certainly as we proceed through our financing aspects

for the partnerships.

I am still reeling a little bit because I don't have a shot at employee of the year, apparently. But I will overcome that. Today our management team that has been up here

has provided a compelling strategy as well as a strong execution plan around those strategies. And what I want to do is I want to build upon that and communicate what

our financing plans are around those strategies as well as how all of that translates into value for our investors.

So first, I'm going to deal with Enbridge Energy Partners, I will transition to Midcoast Energy Partners at the back of the presentation and then take questions. So here

are our key messages from a finance perspective for EEP.

Our long-term value proposition here is, and Mark talked about it, our attractive yield at just under 8% currently with a significant tax deferral around that as well as a

sustainable distribution. That sustainable distribution is complemented or underpinned by the low-risk business model that we have relative to these cost of services as

well as ship or pay contract structures.

Additionally, we are benefited by our parent, Enbridge Inc., who has been quite supportive and we'll touch on some of the examples of that as we move through the

presentation. As these long-lives, secure liquids projects ladder into service that facilitates the growing cash flow for EEP as demonstrated by Guy and also Byron in

their presentations. And that enables us to achieve the 2% to 5% distribution target growth that we have.

And then longer or later in the planning period as Mark noted we get into the ability for the partnership to receive drop-down from Enbridge Inc.

These are major projects that we have that will be coming into service in future periods. Collectively this is $10 billion of organic growth, and it provides a solid return

profile over a long time frame for Enbridge Energy Partners. I want to touch on just a few key aspects associated with this slide.

First, as you move to the left just to touch on Eastern access, Byron noted that the 6B replacement is -- a large component of that is coming into service this month. And

then additionally there will another piece that comes into play in the third quarter. So that is very helpful as it relates to the partnership's cash flow profile in 2014.

Additionally, moving all the way to the far right column you see the contract structures that we have talked about. Again, Sandpiper with a ship-or-pay contract

structure as well as a cost-of-service element that lays across the top. And then further down you have these long-lived liquids projects on the Lakehead system, 30-year

contract structure, no volume risk through that structure and limited capital risk.




36


So, Byron is doing a great job of bringing these in on time, but, to the extent that there are cost overruns and each project is a little bit different, we have quite a bit of

protection associated with that.

When you integrate all those projects coming to service, and Mark showed a ribbon chart and I have got circles. I like circles better. The perspective view of EEP,

basically our risk profile transforms and becomes even lower risk in the future than it does today.

So, if you move all the way into 2017 when Eastern Access, Mainline Expansion and Line 3 have come into service as well as EEP has taken this gas business and

dropped it down into Midcoast Energy Partners, what you see is 75% of our cash flows from our revenues have no volume risk. It is quite compelling.

Additionally, when you look at the commodity risk there is just a very modest element of it exists and is later time periods. So again highly certain cash flow especially

as you move out into the latter period of the partnership.

This is -- when you take our planning period that we've provided here which is 2014 to 2017, so we are staying within those bounds as a consistent theme here from a

time perspective as we move through the presentation. We have $5.1 billion of capital, and we outlined what that looks like today and that is net of the joint funding

agreements. I will touch on the joint funding agreements in just a moment.

Also, to the far right the treasury team has done a great job of putting in excess of $3 billion of liquidity into place, we were using just a very small amount of that as we

exited 2013. That gives us great flexibility, as we look to time our additional capital needs for Enbridge Energy Partners.

Joint funding. So it started with Alberta Clipper, which is in service, and then we have a number of joint funding agreements that are currently in place. I just want to

summarize those briefly. So, Mark noted the strength of Enbridge Inc., this is an example of that as we move through these joint funding arrangements that enable EEP

to participate in these long-lived liquids projects.

Eastern Access, Mainline Expansion the special committee process has been completed. We -- as noted those are coming into service in the near -- over the next couple

of years and we do have that 15% upsize option.

The Line 3 replacement, which what we have done in our plan here is we have assumed that it is a 50% ownership and that there is an upsize option that occurs of 15%.

There is a footnote, it is important, still under discussion with our special committee as it relates to the negotiations with Enbridge Inc. So, we will stand by and see

what that ultimately comes out to. We feel it is probably a good or hopefully in the ballpark estimate for now.

So collectively the Enbridge Inc. joint funding agreements give us $1.2 billion of options to upsize later in the planning horizon when the cash flows of the partnership

are even stronger.

Moving down, we had a -- I mentioned the contract structure with Marathon and Sandpiper, so in effect we have a joint funding their of almost of $1 billion and the

37.5% [capital] interest that Marathon is taking in the project.

So, we are excited with the joint funding agreements that gives us the flexibility that we need to handle a very manageable amount of capital as well as provide us

optionality for upsizing later.

So, I want to transition here to just the 2014 guidance. In February, we had our analyst call and we communicated what our expectations were associated with guidance.

There, we talked about on a fully consolidated Enbridge Energy Partners basis would be between $1.5 billion and $1.6 billion.

What we have done here on this chart is we've taken the midpoint effectively of that range on the second bar you see the green component and the blue component. The

green component represents the standalone component for Enbridge Energy Partners or a net of non-controlling interest. So, the amount of funds or cash flows that will

be coming directly to EEP after joint funding.

So, I want to touch on the $245 million increase year over year and what gives us confidence that we will be able to achieve that. So, as you move to the bottom right-

hand corner of the chart, we talked about Lakehead at an additional $110 million, there are two components to that.

One is the fact that our rates on the Lakehead system have gone up year over year due to the fact that we have this annual cost of service true up mechanism as so we

are truing up for the volumes as well as the cost in 2014.

Secondly, there are growing volumes on the Lakehead system of on average from 2013 to 2014 of 300 million [barrels] a day, we average 1.8 million [barrels] a day in

2013, 2014 and midpoint of our guidance is 2.1 million.




37


When you look at our fourth-quarter numbers on Lakehead we are 1.92 million [Bpd], so you can see that certainly the volumes have come up as we left 2013, as well

just to echo Guy's comments, the volumes are there and they want to move and we are seeing that. So, we feel confident in that rising volume profile we put forward.

Additionally, North Dakota has two components, we have ship or pay contract structures in place around our Bakken system as well as we have some committed

contracts on the Bakken Rail, both of those projects were not in service for all of 2013 they came in around April 2013, so we get a full year of in service, plus the fact

that we have a bit of a stair step in the committed volumes from 2013 to 2014.

So those things are helping the North Dakota numbers as well as the physical volumes that are moving across our system, moving east to Clearbrook, expectation that

those volumes are higher, spreads have come in 2013, we had some very wide spreads as it relates to North Dakota to Brent, they are still there, they still exist, rail is

still a competitor, but we are seeing more volume move on pipe as we go into 2014.

And then finally Eastern Access and Mainline Expansion, we have talked about those already. Those are the cost of service contracts that are coming into service. And

as Byron noted, the first big piece of that is in April, and it looks to be on time. So we are pleased by that certainly.

EBITDA growth outlook. What we have done here is where provided a representation of our predictable earnings and how those increase over time. The 2013, 2014

numbers, or 2013 is actual, 2014 is our guidance.

And then, we have represented what it looks like as these long-lived liquids projects come into service. They are the ones we talked about throughout the meeting today

or the discussion today. And we will be pleased to see them. So again, these are low risk long-term contracts that give us a lot of confidence associated with the rising

cash flows within EEP.

Next slide is one that Mark provided and the comments on my previous slide relative to the growing EBITDA support the fact that our distribution coverage is going to

be strengthening, 0.85x to 0.95x. And our guidance, as Mark noted, we expect to be around 1x in 2015, and then exceeding in future periods.

I want to touch on operational reliability from a financial perspective; this is a question we have had in prior years. I just want to make sure we cover it off. There has

been a lot of work post Marshall associated with our liquids integrity, then a full blitz of our system running in line integrity tools as well as the big program. And here

you see that spend profile and what it looks like over time.

2014 those numbers are expected to come down relative to our guidance. And then, in future periods, we expect that to moderate. So not only have we done all this

work around ILIs and replacements, but additionally, as we have noted, we are replacing a couple of our systems with the latest technology as it relates to Line 6B and

then ultimately Line 3 in 2017.

Funding plan. So for those of you who are comparing, this is the same slide that we showed about a month ago at our Line 3 call, so it should be the same numbers.

What we wanted to represent here is that we have a very manageable funding plan as we look forward. I want to point out just a few key aspects of the plan.

Moving to the bottom right you see the $600 million of equity needs that we project through this time period which we look at as being quite manageable. If you look

back to last year just through our two EEQ issuances that we did, that was $500 million of equity just in one year. And here over a four-year period we are projecting

$600 million.

Some of the key aspects or key assumptions in that as you move up the chart is certainly the plus or minus $2.6 billion for MEP drop downs. This really ties together the

fact that it is in our funding plan that there will be a drop-down of the gas business through 2017 to enable EEP to use this as part of its funding. And so certainly EEP is

vested in accomplishing that.

Finally, I wanted to point out the joint funding callback option or, as Mark noted, it is in effect a drop-down, that we have those options to enable between the 2016,

2017 time period for Eastern Access and mainline expansion. It is in our plan. At this point, we plan to upsize the 15% on these projects.

So, from a capital structure standpoint, EEP continues to target a 50-50 debt to equity ratio there, no changes. And as well our credit metrics are certainly important to

us. Here we show our debt to EBITDA and FFO to interest and that as these projects come into service our credit metrics continue to improve. And that is critical to us

because our investment grade credit rating is very important to us and certainly a top priority, always has been and continues to be for Enbridge Energy Partners.

A quick look at the maturity outlook, you see that there are a number of maturity windows that we can issue into as we look to accomplish the $3.3 billion of debt that

was in the prior slides. An important point here is that as it relates to these future debt issuances, approximately two-thirds of those have been hedged already as relative

to this low interest rate environment.




38


So, we know we are going to build these projects, we know we are going to have those funding needs and so we have done a good deal of hedging when you look out in

future periods. So certainly EEP is a consistent practice there with its parent, Enbridge Inc., which follows a similar pattern.

So, all this organic growth and their contract structures, the manageable financing plan, improving credit metrics and an improving coverage ratio all give us confidence

as management in enabling this 2% to 5% distribution growth target. You get out later in the plan period you have -- we have noted the Eastern Access, Mainline

Expansion options, we plan to exercise those upsizes. And then what Mark noted here is longer term gives us the ability to accept drop downs from Enbridge Inc.

And I just want to emphasize, Mark touched on it, but those first four bullets of examples are all within the existing Lakehead footprint today. So Lakehead will own

them, will operate them, it is just a piece of the cash flow through the joint funding agreement goes to Enbridge Inc. So as it relates to strategic fit, quite strategic. As

well we have noted the Seaway and Flanagan extensions, which are downstream of the Lakehead system, still strategic but not in the existing footprint per se.

So a number of takeaways just as it relates to EEP, secured liquids growth projects, visible distributable cash flow and our manageable funding plan, all those things

work together to enable strong credit metrics and give us confidence in the 2% to 5% distribution growth target that we have for the Company.

So with that I am going to transition to Midcoast Energy Partners and begin with the key messages there -- I think this may be in the next section of your book.

So the first couple of bullets here Greg and Terry hit on, but our plan is to execute on our growth strategy, deliver on our targeted distribution growth rate of the mid-

teens, and accomplish that first drop down in the middle of this year which we've communicated $300 million to $500 million range.

The bottom three bullets really relate to, from a financial perspective, what we are going to do and how that is important. So, conservative capital structure, financial

support from our sponsor, which would be EEP in this case, and then also a disciplined risk management strategy. I will touch on each of those in just a moment.

So MEP was established, as you know, to be a pure play G&P business as well as enable us to focus directly on growing that business, and Greg and Terry did a good

job certainly of outlining that.

What I want to do is as it relates to this mid-teens distribution growth, I just want to talk about the three components there that exist within the arrow. The first being the

8% to 12% on the drop-down. So as you saw in the financing side, for Enbridge Energy Partners, on the 2.6%, it is in EEP's plan. And as it relates to MEP's plan it is

there also. And then we will touch in a moment what MEP is doing to position itself to receive those drop downs.

The other two components are the 3% to 5% organic growth around our existing businesses and the scale of the assets that we have. And then finally the 1% to 2% is

accounting for the fact that we are entering the kind of a low point in the commodity price cycle and getting a bit of a bump as we move through that.

So the bottom of the slide we talk about that drop-down timing. What I want to do is I want to move over to the enhanced access to capital. We have an $850 million

credit facility that is in place. At the end of the year, we had in excess of $500 million available to us. The plan would be that as MEP receives that drop, it is able to

debt fund that, leveraging its revolver and then longer-term looking to term out some of that debt as it moves through the cycle.

So, we think we are well-positioned and ready to achieve that mid-year target. And certainly from an MEP perspective things are in good shape.

From an MEP credit facility standpoint, and Greg touched on this, here you show it more from a pictorial standpoint -- exited the year at a 1.2x, assuming a $400

million drop-down we would be around 2.9x, which is double, well below our covenant ratio of 5x.

For MEP longer-term it's going to establish -- it's not going to come out of the gate at a 50-50 debt to equity target is something that we'll be growing into overtime. But

it is a longer-term funding approach for this entity.

Organic projects, Terry hit on this slide previously. The first couple, I just wanted to emphasize those projects are in service, Texas Express and Ajax. Beckville we

expect to be in service in early 2015 and begin contributing cash at that time. We expect that we will spend about $100 million this year on constructing out the

Beckville Project.

And then finally the unsecured growth projects of $250 million a year that Terry outlined and communicated some examples that we have around the large-scale assets

as well as the Eaglebine and Cline being -- Cline Shale being a couple of opportunities. This information really is what is integrated into the 3% to 5% on the red part of

the arrow in the early part of the slide deck.




39


Hedging, commodity. We continue to take very seriously the commodity position that we have, we have POP, POL contract structures make us long, natural gas and

NGLs. We continue to have this disciplined hedging strategy we have had in place for a number of years.

And to the right you see we have about 55% of our gross margins commodity risked and then after hedging, which is 70% year one, 60% to 70% year one and

approximately 50% year two. That converts that risk profile to approximately 20% commodity risk. And this is done to stabilize the cash flows within MEP and

mitigate the commodity price risk volatility that exists.

This shows the sensitivity to the commodity shifts, we took a pretty heavy -- if you have a pretty heavy sensitivity of the 20% price move within 2014 and 2015 and

here are the associated impacts. We continue to be more impacted by natural gas liquids prices given our contract structures, the natural gas. There is some natural

hedging within the business on the natural gas side and so very modest components as it relates to direct natural gas.

Our commodity price assumptions are laid out here and the internal forecast is consistent with information we communicated during the S1 process. Additionally, we

are showing the latest or updated experts' views of what those commodity prices are. The takeaway from the slide is really two things.

One, our prices here are pretty consistent with the experts. And then additionally as you move down to the chart at the bottom our expectation along with most of the

experts gas prices slowly rise over time and you get a bump in NGL prices as you move through the planning period. So these things combine to provide this 1% to 2%

growth in commodity prices that I talked about at the beginning of the MEP presentation.

Midcoast is benefited -- EEP is providing some additional financial support for the entity. There is a $700 million financial support agreement for any parental

guarantees that are effectively needed by some of the subsidiaries of the gas business that EEP is providing, which we hope to use minimal amounts of as we move

through the year. There will be some aspects of that.

And then also to enhance its liquidity and really storage and ability to store product as needed, there's a $250 million working capital facility that EEP has provided in

Midcoast Energy Partners.

So, I will let you read the key takeaways here and open it up for questions at this point.



John.


John Edwards, Credit Suisse. Can you just remind us -- this is on Midcoast -- on the support agreement, the 250 basis points annual fee, is that effectively a fee on any

amounts that are drawn for support? Or is that a fee on making that support available?


Those are amounts that when it is drawn upon. So if it's -- and at the end of 2013 there were not any draws on that facility.


Chuck Goldblum, Hurley Capital. Some low equity requirements the next few years. Wanted to know if we should look at your current schedule of growth projects as

your plate being pretty full operationally? Or should we look at the low equity requirement as an indication that there is capacity to do more?





40


A couple of things in there. I think that relative to some of our -- the majority of our capital is taken by these liquid organic growth projects. There are some elements

of capital that we estimate and so there may be some elements of organic growth in and around some of our assets so we take that into account.

But there is certainly some additional capacity that exists here, $600 million is very manageable. And so, I think that there is -- certainly to look at other projects that

capacity exists and certainly that is one of the aspects that we looked at when we said what we are going to upsize on the Eastern Access and Mainline Expansion but

even beyond that there is additional capacity that would exist.


And the quick follow up on that is to the extent there is additional capacity and to the extent you do additional projects atop what you have got should we think about

that as incremental to wherever you are in your head on that 2% to 5% distribution growth range?


I think certainly for us to take on, when we look at those projects, we will look at our internal hurdle rates that exist and ensure that it is accretive to our LP unitholders.

So I mean those will be -- those are key characteristics and key decision points for management. Ted and Mark. We have got a mic coming, Mark, it is coming at you.


Just on the equity needs of the $600 million, how much is available under your At-the-Market program? And just how do you think about funding the equity portion?

And then also if you could just discuss how durable to think that $2.6 billion number is for the MEP drop downs?


Yes, so as it relates to -- the question was would we look at using the At-the-Market program? We do have a $500 million shelf that is in place currently. Historically

we have done the At-the-Market program, it has been a couple of years that is certainly is a very viable alternative for us. And I think one of the things that we would

think about as it relates to equity, and as it relates -- Mark, as it relates to the Midcoast question, how viable?




Yes, so we are cautious on the [$]2.6[MEP Drop Down Value] certainly. We looked at the value of the business, there is a plus or minus around it knowing that there is

a negotiation process that is going to occur between EEP and the MEP special committee. So I am a little cautious and not stepping out and making any comments

around -- too many comments around it other than it will certainly be arms length. Yes, Ted.


Ted Durbin. Just on the Sandpiper return, the seven times. I just want to make sure that that is the contracted volumes from Marathon Oil and there is no sort of

uncommitted volumes that are in that multiple. And therefore that multiple gets better as spot volumes move on Sandpiper, is that fair?


Yes, so maybe said another way does the volume -- does the return increase over time --?




41



Does return get better (multiple speakers).


Yes, it is fairly consistent and it is certainly predominantly driven by the ship or pay contract structure that is there. There is an element of assumed return on the cost of

service component, but it is not an extensive upward rising return profile.


Can you give us a sense of the range if you moved more spot volumes what the multiple could get to?


I am going to shy away from that question just because our visibility on Sandpiper is not complete as it relates to some of the commercial arrangements that are going

on there and discussions with FERC, so --. Guy, unless you wanted to say --?


No, good answer.


Okay, all right. Unconfirmed. Okay, well, next up Mark Maki will close up for the presentation. Oh, Greg and Mark.


I didn't have any prepared remarks, but first and foremost we thank you for your interest in MEP for sure and Enbridge as a whole. I know Mark is very appreciative of

the support of EEP. I hope we gave you some clear line of sight on where we are headed in 2014. Kind of what our priorities are for sure at Midcoast is to deliver on the

S1 that we committed to you all as investors. And that is kind of our go forward.

I can tell you from my perspective, I am on a 100-day plan right now, I didn't address it in my remarks, but I will give you an overview of that as kind of understanding

the assets. Unfortunately my first 60 days have been with these guys too much and not with the employees and Terry and his team yet. But that will come in the next 40

days for sure.

But understanding assets, the profitability, what is not profitable, rationalizing those, looking at people and resources, making sure we got the right people in the right

places and doing the right things. And then also stakeholder engagement. And obviously I have been doing a lot of investor engagement but there are also regulators,

customers for sure that I will be laying out a plan of attack on that as well.


Well, thanks, Greg, very much. Again thanks, everyone, for attending today's session, very much appreciate everyone who comes out and spends time with us. Sanjay

of course will be surveying, asking for feedback on the presentation materials and so forth. And we really do appreciate your comments, we try to incorporate that and

things we see as themes throughout the materials in the next year's material.

So again, thank you very much. Lunch of course is served back through the doors here to the left. And look forward to seeing you at lunch. The Enbridge people will

scatter around the tables, again feel free to ask questions. If there is someone there who can't answer the question we will try and hunt down somebody who can. So

with that, Guy, any other kind of closing remarks or --?




42



Well, no, I don't think so. I think the nature of the questions that the room had for liquids pipelines and major projects really captures the essence of the shift that we see

going on in the liquids pipelines business. We have been here talking for years to this audience about growth and securing growth, and we have been very successful at

that.

Now we have got to execute that growth and from the liquids pipeline side of things we have got to be ready to manage the business and deliver the financial returns.

Greg talked about meeting his S1, we need to be meeting the liquids pipeline's financial expectations that the partnership is setting out as well and we are committed to

doing that.


Good. Well, thanks, everyone, appreciate it.

D I S C L A I M E R

Thomson Reuters reserves the right to make changes to documents, content, or other information on this web site without obligation to notify any person of such changes. In the conference calls upon which Event Transcripts are based, companies may make projections or other forward-looking statements regarding a variety of items. Such forward-looking statements are based upon current expectations and involve risks and uncertainties. Actual results may differ materially from those stated in any forward-looking statement based on a number of important factors and risks, which are more specifically identified in the companies' most recent SEC filings. Although the companies may indicate and believe that the assumptions underlying the forward-looking statements are reasonable, any of the assumptions could prove inaccurate or incorrect and, therefore, there can be no assurance that the results contemplated in the forward-looking statements will be realized. THE INFORMATION CONTAINED IN EVENT TRANSCRIPTS IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE CONFERENCE CALLS. IN NO WAY DOES THOMSON REUTERS OR THE APPLICABLE COMPANY ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY EVENT TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S CONFERENCE CALL ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS. © 2014 Thomson Reuters. All Rights Reserved.



THOMSON REUTERS STREETEVENTS EDITED TRANSCRIPT/media/EepEeqMep/...Brian Zarahn Barclays Capital -...

Documents

Transcript of THOMSON REUTERS STREETEVENTS EDITED TRANSCRIPT/media/EepEeqMep/...Brian Zarahn Barclays Capital -...