MEG Energy Corp.

Great, thanks, Donna; and good morning, everyone, and welcome to MEG’s Second quarter conference call. We have in the room with us today, our CEO, Will McCaffrey, and also our CFO Eric Toews.

I remind you that today’s call contains forward looking information, so please refer to our quarterly results and other documentations on SEDAR and our website for further information on that matter. And with that, I'll turn it over to Bill.

Well thanks, John; and good morning, everyone. When you're building a strategy that is fundamentally about long-term values, you try not to get caught up in any individual quarter.

However Q2 2014 might be an exception. This quarter we saw a record production of nearly 69,000 barrels a day, all while undertaking a planned maintenance for the Phase 1 and 2.

This record level of production was supported to a large degree by Phase 2B, which reached design capacity after seven months. And as the result of the strong performance, we're now increasing our 2014 production guidance by 8%.

We also reached record cash flow in the second quarter. And finally, subsequent to the end of the quarter, production for the month of July is averaging 75,000 barrels a day, about double where we were at this time last year.

It was certainly a quarter that achieved a number of key milestones and a quarter where several records were broken. Let me just spend a minute to elaborate on the highlights.

In Q2, we continued with the ramp up of Phase 2B, which reached its design capacity of 35,000 barrels a day just 7 months after first oil and just prior to the turnaround. The story behind the speed with which the ramp-up occurred can be explained by several factors.

First, the high quality of the resource base. Second, our team has a good understanding of the effects various reservoir parameters have on production performance, which really helped us in our predictability.

Third, we’ve been able to customize our operating practices using these reservoir parameters to maximize production from the reservoir. And finally, the continued high level of reliability of the plants and the benefits from the interconnection of our processing facilities also played a major role in the success of the ramp-up.

Now you may recall that during the quarter we had a scheduled 3-weeks plant turnaround for our Phase 1 and 2 facilities. This went according to plan with no surprises and confirmed that the facilities are in good working order.

With the turnaround complete on Phase 1 and 2, we’re now focused on the continued ramp up of our production volume. As mentioned earlier in July, we are on pace to set another monthly record of production of approximately 75,000 barrels a day.

Given our year-to-date performance, we now believe our original guidance will be exceeded. As a result, we’re raising our production guidance for 2014 to 65,000 to 70,000 barrels a day, which would be approximately double our 2013 average production level.

Nonenergy operating costs for the quarter averaged $9.60 a barrel, which include the cost of about $1.90 of it of the turnaround. At these levels, we’re well within the range of our guidance, reflecting efficient operations and a smooth wrap-up [ph].

And as Phase 2B contributes increased volumes, we expect costs should come down further in the second half.

Putting these pieces together, the combination of record production, steady operating costs and strong prices for our blend contributed to record quarterly cash flows of $262 million in Q2. This step change in cash flow represents the beginning of a new chapter for MEG.

Internal cash flows are now poised to be a major contributor to our future funding requirements.

And as we approach the 80,000 barrel a day mark, we’ll begin to look -- we’re looking towards our next major phase of production growth. This will entail deploying RISER to the 2B project, which includes the application of eMSAGP in the reservoir and brownfield expansion of the central facilities.

During the turnaround, we were able to further test the Phase 2B oil throughput capability and found we could process 55,000 barrels a day of oil through that facility. That’s nearly 60% above the initial design capacity of 35,000 barrels a day.

So obviously, this is extremely positive for us, and it helps us map out brownfield modifications that will be required for the 2B facilities.

Now the areas of expansion will focus on the water treating and the steam generation side of the plant as well as further growth in the oil treating capacities. We see our medium-term production growth trajectories occurring over a series of smaller steps rather than 1 big step per developing time.

Obviously, where operations were very strong for us in this quarter and we’re very pleased with that, but let me take a moment to also comment on the pricing and marketing of the quarter.

For the second quarter WCS to WTI differentials narrowed to 19.5% from about 23% discounts in Q1. Here we think we’re experiencing a structural change in the market.

That change is being driven by the additional heavy oil processing capacity of BP's Whiting Refinery, the additional capacity that is now clearing Cushing with the Seaway and Keystone Gulf Coast Pipeline system and the continuing ramp-up of crude by-rail exports. All of these elements are reducing pressure at pinch points in the North American oil distribution system.

In addition to the structural changes underway, we’re also seeing good advancement of MEG's hub-and-spoke marketing strategy as it continues to broaden market access and reduce exposure to localized changes.

On the pipeline side, Enbridge expects the Flanagan Seaway System to come on line in the second half of 2014. MEG has secured long-term capacity on this line, and we are anticipating the call for our share of line fill in the second half of the year.

In addition we have also begun the line fill of our newly completed Access Pipeline expansion. In this context, the strategic importance of MEG’s Stonefell terminal is evident.

It is helping mitigate sales interruptions during the periods that require line fill as well as instances of pipeline apportionment as they occur.

On the rail side. Before the Canexus turnaround, we were able to move as much product on rail as we wanted in Q2.

Q1 we had moved about 17-unit trains for the first quarter, and we moved an additional 33-unit trains in the second quarter, so we’re making good progress there. And we’ll continue to utilize the terminal once Canexus completes its ongoing work to increase throughput capacity.

This work is scheduled for completion in September. On a related front, engineering also continues on our diluent recovery facility.

We expect this facility will be available to support our bitumen rail volume in 2016.

And the last piece of the equation to talk about today is our financial position, and here I’ll turn it over to Eric.

Thanks, Bill. As Bill mentioned we are experiencing a fundamental shift in MEG’s ability to generate higher as well as less volatile cash flows.

This shift is being driven by our continued focus on cost effective growth, solid operational performance and the ongoing development and execution of our hub-and-spoke marketing strategy along with the structural changes in the heavy oil market.

During the second quarter, our bitumen realization was approximately $73.00 per barrel, which was up substantially from the first quarter of 2014 and the full year of 2013. While WTI was also up in the quarter, the main drivers for the increase in our bitumen realization were significant narrowing of the differential for our crude against benchmark prices and a decrease in the cost of our diluent.

For MEG, the narrowing of the differential occurred for 2 reasons. First, as Bill mentioned, structural changes are occurring in the North American heavy oil market which are benefiting the entire industry.

Second, our hub-and-spoke marketing strategy is enabling us to realize better pricing as we continue to diversify our customer base. The cost of diluent was lower for two reasons.

First, as the price for our blend barrel improved, we received greater value for the diluent within our blended barrel, which reduced the cost of our diluent. Second, our hub-and-spoke marketing strategy enabled us to source and transport diluent from multiple points in North America in a more cost effective manner, thus further reducing the cost per barrel.

All of these pieces, expanding production, solid execution and the cost effectiveness of greater control of the value chain have contributed to the higher level of cash flow we are currently seeing. This has a positive impact on the funding of our future capital programs as anticipated 2014 year end cash balances will reduce external funding required for MEG’s 2015 capital program.

As we continue to realize cash flow growth, it will become the primary source of capital funding, allowing MEG to prudently manage its financial position. Additionally, with the next phase of production growth being driven by RISER 2B, the smaller expansions provide MEG with an even greater level of flexibility over our capital program and allow us to more quickly adapt to changing market conditions.

Well, thanks, Eric. To sum it up, we’re very proud of our Q2 results.

The successful ramp up of 2B enabled us to increase production guidance by 8%. RISER on Phase 1 and 2 continue to meet or exceed expectation.

There were no real surprises in the plant turnaround, supporting stable and reliable operations going forward. Nonenergy costs were well within guidance, considering the turnaround that took place this quarter.

Market access both in the big picture and with our own strategy is improving, and our financial pace continues to strengthen, which puts us on a very firm footing to fund our current and future capital programs.

As I noted in my opening remarks, we take a long-term view of the value equation. I think the milestones in Q2 continued to confirm that the strategy that we have put in place is right for the business.

Now on behalf of everyone at ME,G, I’d like to thank you for joining today; and on that note, I’ll pass it back to John.

Great. Thanks, Bill and Eric, for your comments.

Donna, why don’t we open up the lines for questions. Once again, I’ll mention to everyone if we can keep the questions at the strategic level.

Helen and I will be available after the call to answer all your detailed modeling questions. So if we can keep the questions for Bill and Eric at the strategic level, I think we’ll all be very happy with that.

So why don’t we turn it over to you, Donna, for questions.

Just the first question here is for both Bill and Eric. Keying in the comments that both of you made with respect to the increase in cash flow becoming a contributor, major contributor to meeting future funding requirement.

I know you don’t have your ‘15 CapEx guidance out yet, but can you maybe provide some context as to how you’re looking at possible funding requirements over the next, say, 6 to 18 months and especially in the context of your debt levels and targets for your debt? And could you actually see the ’15 budget being fully cash flow funded at this point in time?

Thanks, Mark. Yes.

What we’re doing right now is processes. We are, obviously, starting into our process of budgeting for 2015, but it’s very early stage.

We’re focused on taking the information that we got from our plant turnaround so that we can scope out what the brownfield expansions will look like. In doing that, we’ll commence the engineering and then also get a cost estimate for that area.

That'll form a basis for our 2015 budget. We’re very pleased, obviously, Mark, with the cash flows that are coming out of it, but we don’t think we’ll be externally funding or internally funding everything at this point for 2015, but I can say it'll be a meaningful increase in what we are able to fund from internal sources.

Possibly using line of credit to bridge the gap or how do you think about that?

We’ve got a lot a flexibility, obviously. The debt markets are open to us.

The line of credit’s open, and we’ve got the cash flow. We’ve got lots of sources, but we really need to get to the number, which is the work we've commenced on before we really could really put a pin in it, but you've mentioned 1 source.

The debt markets are open. The cash flows are growing.

The advantage we have is we do our budgets in December, and so we’ll have a good handle on what the cash flow contribution is from this year before we actually have to make that decision.

Right. Without, presumably without going ahead quickly with Phase 3A greenfield, it sounds like the capacity at 2B is capable of handling larger volumes, though it sounds like brownfield capital may not be that -- that might require that much either.

So I'm sort of expecting a lower budget next year, is that fair?

It'd be premature on it right now. The equipment that we have to add is on the water-treating side and steam generation side and some debottlenecking around the oil side of it.

So I just don’t -- we just got the data last month, so I just don’t have that information yet, but it is different than a greenfield obviously. So that’s -- I think you're on the right path that it won’t be -- we don’t think it would be a larger budget, but I just don’t have numbers to really put a pin in anything right now.

Okay. That's fair.

It looks like your updated guidance may still be a bit on the low end. You can take a look at the first half average of 64.

Just even assuming 75 for the second half based off of your July numbers, are we -- should we be expecting another guidance increase in Q3?

No, I don’t think so. But we’ve got a -- I mean right now we’re doing very well, but we've still got a number of things to do to get to the 80,000 barrels a day.

We’re very pleased, obviously, with the progress with 75,000 thus far. July that is tempting to think that way, but there’s a long ways to go, and we do have to average the full year in it, including the turnaround and everything else there.

So we feel it’s a realistic range right now, but we’ll monitor it.

Okay. Eric, you mentioned how much is being shipped by rail in the second quarter.

Can you comment as to the impact that had on netbacks on Q2?

yes. We don’t -- Mark, this Bill.

We don’t actually put out the breakdown that way on it, but we can just tell you that if you are able to get to my end type prices we’ve mentioned before, the transportation costs, about $15.00 to $17.00 a barrel and, as I said, in Q2 we had about 33-unit trains moving. So it gives you a flavor for a lot of that.

Okay. With the interruption at the Canexus facility is that still a good estimate for Q3?

At this stage, we don’t know. We got to see them come back on.

We certainly have lots of options on to move it. If they are on and the volumes capacity is there, we’re certainly interested in moving a lot of the barrels by rail.

We are prepared to do that if it’s available, but part of MEG’s strategy on hub-and-spoke is to have the flexibility to turn it on a dime in terms of where we send these barrels. And so with Stonefell fully operational and everything, we are prepared to move barrels which ever ways is most economic for us.

Okay. And Bill, you did make mention of the diluent recovery unit.

Can you maybe provide any additional color you might have at this point in time in terms of possible size or cost or when you might be prepared to make those guidance numbers?

yes. I think we'll have better handle on it in the next -- ah, geez, I don’t know if it’s probably next quarter or not, Mark.

We’re just doing the engineering on it right now. We have put an application in for 60,000 a day on bitumen movement, but we would break that up into probably 3 tranches.

And it’s really a capital budget decision on it at the time. So the application is one thing.

It’s the decision in terms of how much we do right off the start. Those are all things we’re looking at right now, but we do like it.

We do think it’s going to be a very viable way of cutting our transportation costs while maintaining the flexibility to move to numerous markets via the unit train, which I think that combination is going to be competitive in a lot of ways with some other pipes.

A few things. One is it looks like you CapEx is trending below.

If you assume flat spending for the second this year, you actually might come in below your budget, even below your budget before that contingency that you have in your plans. Is that the way to think about that?

So that’s another uptick potential in terms of the free cash flow or I guess the CapEx versus cash flow. And also you did mention I guess that your operating costs in the second half could potentially trend down.

While you raised your production guidance, you didn’t lower your nonenergy OpEx guidance. So wondering if that side of the guidance could come down?

Sure. Well, on the capital end of it, some of that we are lower in our first half than if you took the $1.6 million plus $200 million in discretionary, so $1.8 million there.

If you took that and cut it in half, we’re certainly lower than that. Some of it’s timing through on it, Phil, so right now we’re comfortable with that capital budget.

We are doing engineering in a lot of areas, so that doesn’t tend to use the dollars as quickly as actual purchase of equipment and construction of equipment and facilities, so we’re in a phase of engineering in a lot of components of what we’re doing right now. On the ops side, our guidance is $8.00 to $10.00 a barrel.

Obviously, we’re at $9.60 for the nonenergy -- this sets [ph] for nonenergy that is. But our guidance was $8.00 to $10.00 on nonenergy, and then we are $9.60 this quarter.

If you took the $1.90 off that we had for the turnaround, I mean that, obviously, puts us on the south side of our range, but that’s just 1 quarter, and we need to go through some more time before we’ll get our operating guidance, but we feel good -- we’re in good shape right now on it.

Okay. So just clarifying the CapEx.

You’re comfortable with the $1.6 million or the $1.8 million?

$1.8 million with the discretionary, and we’re comfortable on that.

Okay. And finally, when you discount you some math [ph], it seemed like your last week of June production actually could have been higher than 75,000, maybe 80 plus, is it not the case?

And if so, is that’s just because you’re able put a lot more volumes into the 2B? Because as you said, you tested at 50,000 a day?

yes. If you look at the -- with the plants being able to handle 55,000 barrels a day, that allowed us to get our 69,000 of Q3 results, which I think is stellar.

I mean that’s impressive I find that we’re able to do that with a 3-week turnaround. To answer your question, we did see some flush production towards the end of the quarter, and so we did touch on 80,000 a couple of days on that part.

But the lion’s share is due to the 55,000 that we were able to put through the plant during the turnaround, which I think is exciting. And we still feel comfortable that we’ll hit the 80,000 by somewhere early in ’15.

It -- because it takes a little a while at the tail of these things to actually get that last bit of production. The easiest part is when you turn on all the wells and they start producing, but then you have to optimize them all and grow that.

You got to deal with the clients that you’re dealing with, so it’s more complicated than just trajectory of where you’ve come from. So, again, I feel comfortable that 80,000 is a good target for early in 2015, and we’re well on pace for that.

We talk a lot about the rail system, but I'm wondering if you’re using your barges a lot right now? Or if you decided to start to lease those out to third parties, kind of in the context I guess of delays to Enbridge's pipeline, Flanagan maybe coming online, if we could see a ramping up of barge volume in addition to your rail volumes, of course?

Sure. Yes.

No, our barges are active. When we’re using them, they're, obviously, in our use.

Otherwise, we do lease them out, but we have ability to pull them back and use them on a moment’s notice, and so they are very valuable to us. We like having them.

We -- even when they're [ph] not in use for us, we’re certainly covering our cost in that area. So they are valuable.

They are options to get to the eastern part of the Gulf Coast and very effective for overall. But that’s part of our strategy is we are trying to make sure we got maximum flexibility to use them when situations change in different areas.

Can you provide any context -- I know you'll probably dodge the question of that, but can you provide any context maybe as to how much volume went down to the Gulf Coast by barge during the quarter? Or is that something you still want to keep pretty close?

You’re right about dodging the question.

No, no problem. But see, what we do is we finally do have competitors on line, and we do want to make sure that we do the best thing for our shareholders, so we don’t want to be -- we’re not trying to be cagey on that.

We just have to realize that we do have others on the line that take this information and use it not necessarily in the best interest of the company. Thanks, David.

Maybe a bit of a longer term outlook here for you guys. Just given what you’ve seen with the ability to add more throughput through the existing developments and then with the RISER initiative, now how should we be thinking about the future expansion at Christina Lake and then ultimately Surmont?

Is there enough to do at Christina Lake here through the end of the decade, where that’s going to be focusing your efforts? Or is Surmont going to be something that you’re still maybe going to be targeting to get online by the end of this decade?

Or is that now getting pushed out a little bit? So I guess just trying to get some clarity on some of the longer term development timeline from you guys?

Sure. Yes.

I would say the next 3 years -- 2 to 3 years are focused on brownfield, but we do have plans to move forward on the growth of Surmont. It’s in application right now.

We do really like that property. We think it’s tremendously valuable, and so we are definitely focused on moving that forward toward the end of this decade.

And further growth at Christina Lake too.

What we’re trying to do there, by the way, is as we use the brownfield as -- because of its ability to allow us to build things in smaller pieces, it gives us greater control on our capital budgets; but it also accelerates our cash flows, which allows us to fund those other projects on a -- from more internal sources. So it’s all positive that way.

And so to us they are extremely attractive economics, the brownfield, and they warrant being in front of the rest, but then it also allows us to take that cash flow and develop future greenfield projects, including Surmont.

I just have a question for you with regards to the power sales. I noticed operating expenses -- nonenergy operating expenses were down, and obviously, you were affected by the increase in natural gas, but there is also some commentary with regards to lower electric sales because of new power that had been built up.

Is that a trend then that we should expect going forward?

yes. Actually what happened is we have lower power of prices in the province because there was extra generation on -- in this last quarter.

But the way we look at power prices is that we will see a certain price for power, then we’ll see a super spike for it. And really, even yesterday there was a super spike on power.

So power prices are very volatile in the province, and I think you have to take an average that takes into account those super spikes. There are plans later in this decade to start to retire the coal-fired plants without a real replacement for them at this stage, so MEG is well positioned should that occur.

So in the meantime can we -- should we expect that's it's going to be fairly volatile in terms of more positive 1 quarter, more negative the next?

yes, I think that’s fair. That is not unusual.

That’s actually what we actually always see. This quarter I believe we offset it by 52%, our energy costs.

So in a down -- was it 5% or 30%? May [indiscernible] 30%.

So I think it’s 50-something percent in July, but I could be wrong. But the point is, is that even in a down quarter it’s still having -- on power prices, it’s still having a meaningful effect on offsetting our energy costs.

Most of my questions have been asked, but I just want to clarify a couple of things here. First on the 80,000 barrel a day target you talked about there, is that -- does that include any RISER?

Or does that just reflect the full ramp up of 2B?

At this stage, it includes RISER for Phase 1 and 2 because that’s already implemented. It includes ramp up of Phase 2B, but it also includes efficiency gains on 2B, which is part of the early stages of RISER.

It wouldn’t really include a lot of the debottlenecks that we will have to do at the plant. Those are going to take us a series of steps that we'll do through 2015 and ’16 in order to reach targets in 2017.

That work's just in the design phases right now.

Okay. The other question I had was just on the -- with the Canexus plant down, do you guys have full access to market or full access to full access to pipe while that’s down?

Absolute. Yes.

We are pipeline connected. Our access pipeline goes right into Edmonton, which is a connection to the main tank farm there and allows us to use any pipes that come out of that area.

And what are you guys seeing as far as apportionments and potential impact on the differential going into Q4?

The differentials through the rest of this year look relatively stable. There will be some apportionments at different points in time, but that’s just one of the strengths of Stonefell really that allows us to absorb changes that occur and redirect those barrels, and that facility is gold for us.

It’s working very well.

Great. Thank you, Donna; and thanks once again, everyone, for listing into our second quarter conference call.

Of course, Helen and I will be available after the call for any further questions that may come to mind. And with that, thanks again, and everybody have a good day.

Bye now.