Al Monaco, President and CEO,

Enbridge, Inc.

TD Securities Calgary Energy Conference

Hyatt Regency Calgary Calgary, Canada

July 9, 2014 (check against delivery)

2

Slide 1 – Cover Slide (Introduction)

Two years ago, we were all consumed (industry, governments, capital markets) by

the double discounting of crude oil prices and the impact on producer cash flows.

Discounted WTI vs. Brent, plus a widening heavy-light differential.

A double whammy for Canadian producers in particular.

The imperative – except maybe for the refiners who benefit from lower feedstock

costs – was, and is, market access.

We’ve seen a recent improvement in prices.

But while the crisis has been dampened somewhat, we’re not out of the woods; far

from it.

On the horizon, North American production is expected to grow at a rapid pace . . .

. . . yet much-needed new energy infrastructure is still challenged.

And now, uncertainty in Russia and Iraq is raising renewed concern around security

of supply.

That means a risk of higher oil prices that could affect economic growth . . .

. . . but, it also points to the opportunity for Canadian supply in global markets.

In a nutshell, that’s why market access remains a strategic imperative, both from an

industry and public policy perspective.

So, that’s what I’ll focus my comments on today in these 4 areas.

3

Slide 2 – Agenda

Today, we need to think of energy within a global context, so I’ll begin with that

perspective, followed by North American fundamentals (focusing on the crude oil

market).

Then I’ll discuss the opportunities and challenges of market access.

And conclude with a few comments on how infrastructure players think about project

execution to make market access a reality.

4

Slide 3 – Legal Notice

I’ll reference forward looking information, so the usual caveats apply.

5

Slide 4 – Enbridge Footprint

To highlight our perspective, this map shows the Enbridge footprint.

Most of you know our asset base so I won’t go through this, but a couple of points:

First, our crude oil and natural gas systems have exposure to key basins and

markets.

Our crude lines are strategically located and you’ll see how that’s coming into play

in terms of market access.

Second, two-thirds of our earnings come from liquids pipelines.

While our natural gas, renewables and logistics businesses have grown nicely, the

pace of liquids growth is hard to match.

In fact, the size of the pie and the blue slice will get larger as we complete our

newest wave of projects.

6

Slide 5 – Global Energy Outlook

There’s no doubt global energy needs will continue to grow, driven by:

o Economic and population growth of some 2 billion;

o Greater urbanization; and

o The desire for increased standard of living in developing countries.

On the other hand, we’re making progress on efficiency as energy is growing at a

slower rate relative to GDP for OECD countries.

Also clear is the expected shift in the energy supply mix to natural gas because of

its abundance, lower emissions and efficiency for power generation.

Renewable energy is the fastest growing, although still relatively small.

The overarching point is that we’ll need all sources of supply to meet global energy

needs.

Focusing now on the largest of those bars, the crude oil market.

7

Slide 6 – Global Crude Oil Demand Outlook

Global oil consumption is expected to grow by 17 million to 106 million bpd by 2030,

driven mainly by China and India.

Last year China overtook the U.S. as the largest net importer of crude oil.

And growth of more than 6 mmbpd is expected by 2030.

And new refining capability – increasingly being designed to process heavier crudes

– is being constructed at the same pace (1.1 mmbpd is currently in progress).

As we know, OECD consumption will be well behind due to slower economic

growth, increasing fuel efficiency and changing demographics.

8

Slide 7 – Global Supply Growth

If you look at how that increased demand will be satisfied, about a third will come

from Canada and the United States.

Canada is expected to contribute roughly half with the other half being from U.S.

tight oil.

And our systems are accessible to a good chunk of that growth.

I won’t get into an oil price forecast, but Brent should be stable at around the $100

mark.

Limiting the downside is consumption growth and the fact that about 1/3 of the

world’s new production requires more than $80/barrel to be economic.

Let’s switch gears to North America.

9

Slide 8 – North American Supply Growth

There’s no doubt we have a tremendous opportunity in front of us . . .

. . . all in, we expect supply to increase by 7 mmbpd over the next 10 years.

This will be a huge competitive advantage for the continent that stems from:

o Quality, scalable unconventional resources that come with minimal

exploration risk

o We have the skills and technology to develop those resources (NA is at

least 10 years ahead)

o And availability of capital and well developed markets

Canadian oil sands should account for about half the increase growing to 5 million

b/d by 2030.

That part was well understood but what caught us off guard was light-tight oil

growth.

U.S. production now exceeds imports and last year growth exceeded the 9 fastest

growing countries combined.

In June, the Bakken crossed the 1 mmbpd mark.

These barrels need to find a home – and that’s the market access imperative.

Complicating that though is that heavy and light barrels each need to find the right

markets.

I’ll come back to that in a moment.

10

Slide 9 – U.S. Crude Demand and Sources of Supply

U.S. crude oil consumption will be pretty much flat – no surprise there.

By the way, gasoline consumption is actually expected to decline by about 20%.

Supply wise, growing continental production will continue to displace waterborne

imports – most lights are already being backed out.

This is where we usually get into North American energy self-sufficiency.

It’s theoretically possible, but the reality is that U.S. refiners will always want access

to foreign supply.

Conversely, producers will always demand optionality to multiple markets, which

raises the question of U.S. exports.

That will take time to sort out, but in my view we’re headed in that direction:

o Crude is already being exported to Canada and small amounts

occasionally re-exported under license elsewhere;

o We just saw the re-classification of some condensates that will allow their

export;

o Some 3.7 mmbpd of liquids and refined products were exported from the

U.S. last month;i

o And we have some 38 Bcf/d of potential LNG projects in development in

the U.S.ii and another 25 bcf/d in Canada.

But in the meantime, where’s all this crude going to go?

11

Slide 10 – North American Refinery Markets

This slide captures the key refining markets (pies) and their sources of feedstock

(bars).

The eastern Canadian and U.S. PADD I market is smallish at 2 mmbpd and it’s

mostly configured to run light barrels.

This is an excellent opportunity for Canadian and Bakken light barrels to displace

imports.

The 3.5 mmbpd U.S. Midwest market is ideal for heavy barrels especially given

recent coker additions.

But don’t underestimate eastern PADD II for light oil refinery take.

The U.S. Gulf Coast market is the largest at 8 mmbpd with significant heavy refining

capability.

Just look at the makeup of the feedstock bars – there’s only a trickle of Canadian

crude reaching that market (but more is on the way).

Therein lies the opportunity for Canadian heavy barrels – and it’s equally powerful

for U.S. refiners facing declining supply from Mexico and Venezuela.

Now let me outline 3 challenges facing our industry and that are driving our own

strategy.

12

Slide 11 – Challenge #1 – Reconfiguration of Pipeline Grid Underway

To be blunt with the first challenge . . .

We have lots of pipe in the ground, but not enough, and it’s been flowing in the

wrong direction for today’s fundamentals.

Over the past 30 years infrastructure investments have been geared to address

declining production and the need for ever more imported crude.

Crude mostly flowed from coastal regions to inland markets.

Today, the game is all about moving barrels the opposite direction - from inland to

coastal markets.

Reconfiguration of the pipeline grid is underway but it hasn’t kept pace with supply

growth.

13

Slide 12 – North American Regional Pricing Disparities

Here’s what happens when infrastructure lags production growth.

You’ll notice natural gas prices are on this chart – that’s because the issue of the

need for global connectivity is broader than crude oil.

I’ll focus on heavy oil prices in blue.

Over the last year, WCS traded $15/bbl off equivalent quality Mayan crude on the

Gulf Coast.

With good connectivity, the basis should reflect the cost of transportation of about

$7 – $8, not $15.

If you look at the peak levels in the box, that basis widened to $34 last November.

At the same time, the WCS-WTI differential surpassed $41/bbl and that stretched to

nearly $52/bbl relative to Brent pricing.

The problem is a lot worse against Asian heavy – the average dislocation is $26/bbl

– with a peak of $52.

The light oil story is the same.

The corollary is that Canadian and U.S. East Coast refiners are at a competitive

disadvantage given higher priced foreign feedstock.

This entire situation screams for new infrastructure.

These price dislocations are problematic at any time, but more so given the second

challenge – the cost of bringing on new production in North America.

14

Slide 13 – Challenge #2 – The Cost of Adding NA production

This slide shows the range of break-even prices for various new sources of global

production.

As you can see, oil sands and shale oil are at the mid-to-higher end. . .

. . .which means they need a higher threshold price to achieve required returns.

So, world price signals are ultimately needed to ensure continued investment

(global connectivity).

Especially given mounting cost pressures from:

o The sheer number of new projects across the value chain, including LNG;

o The impact of emissions regulation, whether explicit or not, implied costs

are being factored in for existing operations and new investments;

o And extended timelines and uncertainty to move through the regulatory

process, which increases the cost of capital;

Let me expand on that last point as the 3rd challenge.

15

Slide 14 – Challenge #3 – Opposition to Energy Development

Actually this is less about regulatory requirements.

The real issue is growing concerns over fossil fuels and energy development.

Since pipelines are seen as energy enablers, we are at the center of this polarized

debate.

How did we get to this point? A few reasons.

One is heightened legitimate concern around climate change and the impact of

GHGs .

A few high profile incidents raised concerns about safety.

By most measures the energy industry is safe, but public confidence has been

shaken.

Another issue is a well-organized strategy by some to attack transportation conduits

– stop pipelines and you stop energy development.

And these factors are playing out within a much broader context – they’re no longer

local; they’re national and global in scope.

This isn’t just noise.

The fallout is that today, regulators, employees, shareholders, political leaders and

the public – expect more of energy companies.

And frankly, that’s the way it should be.

I’ll come back to how we’ve responded in a few minutes.

16

The natural question so far is what are we doing to address these 3 challenges and

the market access imperative?

17

Slide 15 – Steps to Market Access

The chart depicts the 3 steps required for market access.

The first priority is to increase regional takeaway capacity.

Second, is to reach coastal markets so producers can achieve global pricing and

refiners can get access to reliable supply.

And finally, we need to achieve global connectivity.

To illustrate, I’ll go through some of our initiatives which are well underway.

18

Slide 16 – Liquids Pipelines: Regional Infrastructure

On our regional strategy, our two main conduits provide over 1 million barrels of

capacity to the Edmonton and Hardisty hubs.

o The beauty of these systems is they allow us to bridge producers’ interim

needs as volumes ramp up . . .

o . . . which is critical for phased oilsands projects.

o We’re building another 2 new lines to connect the Fort Hills mine and to

bring diluent north.

o We have a similarly strong position in North Dakota.

o Our Sandpiper project, twins our North Dakota system and extends it to

our Superior hub (adds a further 250,000 bpd of takeaway capacity).

19

Slide 17 – Capacity Outlook – WCSB Takeaway*

This slide shows the outlook for production growth and pipe capacity out of the

WCSB.

The black line shows production – the dashed line is our high case.

The red line represents ideal pipeline capacity to buffer against disruptions.

The solid grey and purple areas show existing capacity and expansions . . .

. . . while the solid and hashed orange captures announced projects – XL, Gateway,

TMX and Energy East.

While those projects provide significant ex-Alberta capacity, obviously, there's

uncertainty around them.

The lighter orange assumes the announced start date and the solid orange shows a

24-month lag.

The point is we still see a risk between growing supply and availability of pipeline

capacity.

And of course rail has been a stop gap for this uncertainty.

But the broader takeaway is that producers are placing a very high value on . . .

. . . assuring export capacity out of the basin and optionality to all markets.

20

Slide 18 – Enbridge Providing New Market Access

Our market access strategy is straightforward – move heavy barrels to heavy

markets (blue), and get light oil to light markets (orange).

Our U.S. Gulf Coast heavy oil solution (green) adds 600,000 bpd of capacity though

Flanagan South and our Seaway joint venture.

[The Seaway twin is now mechanically complete and Flanagan South is on track for

late Q3 completion.]

Our Eastern Access initiative (red) opens access for growing domestic supply.

[We expect to complete the reversal of Line 9 by the end of this year.]

This helps ensure the competitiveness of Quebec’s 2 refineries, which represent

about 20% of total Canadian capacity.

And our Light Oil Market Access program –(yellow) – is geared to move growing

light oil from western Canada and the Bakken to eastern markets.

So, all in, we’re executing projects today that will open up 1.7 mmbpd of incremental

markets over the next 3 years.

We’re also undertaking a major enhancement with the replacement of Line 3 to

provide customers with greater surety to key markets.

Importantly, across all of our projects, we’re capitalizing on existing pipe in the

ground and ROW . . .

. . . which minimizes our environmental footprint and we can get crude flowing to

market sooner at a lower cost.

21

Slide 19 – Northern Gateway

In terms of next steps, it’s clear that Canada needs to connect to global markets.

As you know, the federal government approved our Northern Gateway project.

A very important outcome in that we now have evidence that the project can be built

and operated safely . . .

. . . that the environment will be protected, and that it’s in the national interest.

But it was more than that.

The JRP concluded that Enbridge has gone beyond what’s required from a

regulatory perspective on many fronts.

Our objective is to build a world class project and that’s the message that the report

conveyed.

Our priorities now are to address the 209 conditions and close any remaining gaps

with BC.

And, of course, we have more work to build further support among some First

Nations.

Given the interest in the recent Supreme Court decision, let me comment briefly on

that.

This is obviously an important decision for First Nations, our country and for

industry.

In the case of Gateway, the decision clearly reinforces that we’ve taken the right

approach . . .

22

. . . which has always been to come to agreement through dialogue and to build

economic partnerships with First Nations.

We’ve always taken Aboriginal rights and title into consideration.

We’ve been in discussions with First Nations communities whose territory is within

80 km of either side of the pipeline for a number of years.

Significantly, we have equity agreements with 26 First Nations and Métis groups

which will make them true partners in the project.

More broadly, our business involves cooperation with landowners across North

America and we’ve always found a way to work together.

23

Slide 20 – Narrowing Regional Pricing Disparities

So the question is; are we making progress? The short answer is yes.

Prices have improved across a number of regions.

As you can see, we’ve seen a narrowing on the WCS-Maya differential of late

($11/bbl spot).

Additional PADD II coking capacity increased heavy demand on our system.

Our Spearhead and Seaway conduit has also enabled some heavies to reach the

Gulf Coast.

And we’ve progressed well on capacity enhancements and optimization initiatives

with industry including:

o Improved scheduling of barrels entering and leaving our system;

o Pooling of similar quality crudes – from 43 to 23 types;

o Minimizing the impact of maintenance outages; and

o Allocation of crudes between our 6 lines.

As a result of these measures, throughput on our system has steadily increased

over the past few months.

24

Slide 21 – Pricing Outlook (2020)

If the earlier price map was the “before” picture – this is what we should expect as

“after”.

It shows the IHS forecasts of regional pricing for 2020.

With adequate infrastructure – the regional prices should reflect the cost of

transportation.

As pipeline projects go into service over the next few years . . .

. . . the basis should narrow, resulting in higher netbacks for producers.

Let me spend just a couple of minutes on managing execution of large capital

programs to facilitate this growth.

25

Slide 22 – Executing the Capital Program

There are many factors, but I’ll focus on a couple that I think are most important.

First and foremost, you need to have top notch project management capability.

We’ve created an industry-leading supply chain cluster that takes a long view of

construction, labor and equipment markets.

An example is that for our largest input, pipe, we’ve secured best possible pricing by

base-loading a high quality mill.

We’ve developed world class skills, processes and discipline, recognized by the

super majors.

And as you can see by the bar chart, that’s resulting in good capital cost

management.

Another part of the equation is maintaining financial strength through a period of

significant capital build.

That means ensuring ample liquidity to withstand market disruptions, and strong

credit ratings.

And it means continuing to develop good access to capital markets on favorable

terms.

26

Slide 23 – Earning Public Trust

Also critical to execution in today’s environment is gaining public acceptance and

support for energy infrastructure . . .

. . . responding to the heightened scrutiny from our regulators and the increased

expectations of our stakeholders I talked about earlier.

To Enbridge, that means putting safety and environmental protection ahead of

everything else . . .

. . . setting sights on not just meeting regulations, but exceeding them . . .

. . . and engaging our stakeholders through transparent, open dialogue.

And it means investing in maintenance of the system, the newest in integrity

management technology and advancements in leak detection.

The bottom line is that we need to achieve the benefits of economic development in

a sustainable way.

Before I conclude, I want to briefly highlight what our market access strategy means

for Enbridge.

27

Slide 24 – Industry Leading EPS & DPS Outlook

Today, our enterprise wide capital program stands at $42 billion, $37 billion of which

has been commercially secured and will be put in service by 2017.

That investment drives the earnings and dividend growth outlook you see here.

With that we’re confident in delivering industry leading average annual EPS growth

of 10-12% though 2017.

And there a number of factors that bode very well after 2017.

With respect to dividends, we would expect to see a growth rate that tracks EPS.

With the amount of capital we’re putting into the ground over the next few years,

we’ll see strong cash flow growth.

28

Slide 25 – Key Takeaways

To sum up, global energy consumption will continue to grow – and we’ll need all

forms of energy to meet demand.

North America is on the cusp of playing a much larger role in the global energy

market . . .

. . . the main drivers are our endowment of excellent resources and the stability of

our continent.

But to achieve that, we need better connectivity to markets.

As you saw, we’re making good progress in opening up new markets within North

America, although slower than we’d like.

And as production continues to rise we’ll need more infrastructure and global

connectivity.

[Pause]

The prize is large and it will put our destiny within our own control.

If we’re successful, Canada will realize fair value for its resources.

That will support the flow of capital to the energy sector.

And it will have tremendous economic knock on effects and our ability to maintain

our social safety net in this country.

[Pause]

Energy development requires public trust.

29

And to maintain that, the industry is placing the highest priority on safety and

protection of the environment.

Finally, we’re seeing a more balanced discussion take hold today.

Along with growing appreciation of the significance of energy to the Canadian

economy and our quality of life.

The theme of my comments today has been the need to focus on market access as

our North American strategic imperative.

We need to make it happen –and that’s what Enbridge and industry are doing!

i IEA – April 2014 (most recent month available at June 27

th – next update will be end of July) – total exports of “Petroleum & Other Liquids” of

3,966 kbpd; however, of that total, 268 kpbd was exports of crude oil ii RBC Capital Markets report, March 26, 2014 – US 9.3 bcf/d approved by DOE; another 28 bcf/d remaining proposed projects. Canada – 17 to

26.5 bcf/d proposed export projects – 7 export applications totaling 14.6 bcf/d capacity approved by NEB.