MEG Energy Corp.

John Rogers - VP, IR, External Communications Bill McCaffrey - President, CEO Eric Toews - CFO

Greg Pardy - RBC Capital Markets Shaun Polczer - Mergermarket Mike Rimell - UBS Securities Maryana Kushnir - Nomura Asset Management Ryan Larson - Strategic Income Management Blake McWherter - PineBridge Investments Peter Martin - WR Berkeley Andrew Milano - CBC Credit Partners Carl DeMuth - Goldman Sachs

Thank you, Mary. Welcome everyone to our fourth quarter conference call.

For our conversation today we have with us our CEO, Bill McCaffrey, and our CFO, Eric Toews. To start off Eric will focus on our results during Q4 and the full year, and then Bill will take us through a look at 2016 and beyond.

I will remind you today that the call does contain some forward-looking information, and please refer to our other documents at SEDAR and our website for further information on that subject. So without further ado let's turn it over to Eric to get us started.

Eric.

Thanks, John. And good morning everyone.

As John indicated, I'll start by discussing MEG's operating and financial performance over the past quarter and highlights of the full year. Production for the fourth quarter came in at 83,514 barrels per day, a new quarterly production record that builds on our previous record set in the third quarter.

With strong results over the full year, we also achieved record annual production volumes of just over 80,000 barrels per day. That represents a 12% increase over 2014 volumes and is in line with our 2015 target.

This production increase was achieved even with an overall 23% reduction in our 2015 capital budget after adjusting for capitalized turnaround costs. While production volumes were on target, our operating costs came in even better than anticipated.

We achieved a record non-energy operating cost of $5.66 per barrel, and record net operating costs of $8.02 per barrel for the fourth quarter. In addition our yearly non-energy operating costs were $6.54 per barrel, which is below guidance, and almost 20% lower than the previous year.

This contributed to a record low annual net operating cost of $9.39 per barrel for 2015. Despite increased production and lower operating costs, the negative low commodity prices resulted in cash used in operations of about $44 million, or $0.20 per share in the quarter.

On a full year basis cash flow came in at $49 million. Looking at the bigger picture MEG's strong financial liquidity and its ability to maintain operations with very low capital investment are defining attributes of the company.

With respect to financial liquidity going into 2016 we have more than $400 million of cash on our balance sheet, as well as on going access to our US $2.5 billion undrawn credit facility, which is not due for renewal until the fourth quarter of 2019. Our credit facility is like all of our existing outstanding debt, free of any financial maintenance covenants, and is also not subject to any borrowing based re-determinations.

In addition, we are taking initiatives to maintain and further strengthen our liquidity position. In the fourth quarter, we realized the proceeds from the sale of a non-core asset, and today announced the reduction of our 2016 capital budget by approximately 50% from $328 million to $170 million.

In the current low oil price environment, we are also moving our planned maintenance forward to begin in March. As a result we would expect the production impact from the planned maintenance to be approximately 8,000 barrels per day in the first quarter.

With that I will pass it over to Bill to talk a little further about our plans.

Thanks, Eric. As Eric mentioned, we're pleased with our operating performance, and we continue to make significant moves towards strengthening the business.

Our ongoing strategy in the current environment is to minimize the impact of this low point in oil price, and to do that we really have a two part overall strategy. First, while we have made significant progress on finding ways to reduce our costs, we're going to continue to focus on ways to drive them down lower.

At the outset of 2015 our operating costs were already very competitive. Over the course of the year we put in place initiatives that helped further reduce our net operating costs by 20%, with the primary driver being a 25% reduction in non-energy operating costs, now these reductions were really the result of four things, efficiency gains through higher volumes, reducing our workforce, rethinking how we approach the operations and maintenance of our business, and negotiating reductions from our suppliers.

As an example on the last point, our focus on increasing operational efficiencies has enabled MEG to reduce the number of contractors on-site, and allowed us to negotiate reduced rates. Overall there's been a 45% drop in third-party service costs for about $0.70 a barrel.

This is just one example, but this is the fun of this as we still feel we are the early days of this highly focused process of driving improvements across the board. Now while we are continuing to work to reduce our operating costs, we're also reducing our capital costs significantly.

Now as Eric mentioned, we're now targeting capital investments of $170 million in 2016, which is almost 50% lower than our previous guidance. The reduction is possible because of a deferral of growth capital, as well as the efficiency gains from enhancements to our EM SAGP process in the fourth quarter of last year.

The efficiency gains resulted in higher well productivity that we had not initially anticipated. This has the added benefit of reducing 2016 sustaining and maintenance requirements to below $5 per barrel, versus a previous estimate of $7 to $8 a barrel.

Now it's important to realize that while we have significantly reduced our sustaining capital with the efficiency gains we have achieved we continue to target production of 80,000 to 83,000 barrels a day in 2016. At current prices we cover all variable costs with the remaining cash flow contributing to coverage of our fixed costs.

In the event that we did see sustained low oil prices that would not allow us to cover our very low cost, we would have the option to defer sustaining and maintenance capital and temporarily let the reservoir enter natural decline, but I want to emphasize that, in the event. Today we are covering that and still contributing to our fixed costs.

If we did that however, this would result in single-digit slow decline rates, which is quite a bit different than might be seen with shale oil projects In addition to cutting costs the second part of the strategy is to maintain our significant liquidity position. As noted we have reduced our capital budget, and finished 2015 with more than $400 million of cash in the bank, and a US $2.5 billion undrawn revolver.

All of this provides MEG with significant financial liquidity in a low oil price environment. Finally, MEG continues to progress on the monetization of its 50% interest in the Access Pipeline.

A sale of the pipeline will further enhance our financial liquidity, and management and the Board are very focused on a successful completion. We continue to work diligently to get this done as quickly as possible, while at the same time ensuring the transaction is in the long-term interests of our shareholders.

In summary driving costs lower and preserving liquidity will enable us to weather the current storm. Over the past year we have put in place a series of initiatives that help us navigate through the current low-price environment, and in 2016 we're going continue to refine those initiatives.

Looking forward, MEG is well positioned to reinitiate Brownfield growth projects once market conditions improve. So with that, I'll turn it over to John.

Thanks Bill, and Eric for your comments on 2015, and also looking forward into 2016. We will open it up for questions at this point.

I would remind you if we could keep the questions in the interest of all of the people on the line at the strategic level. And Helen and I will be happy to answer your specific modeling questions after the call one-on-one.

So with that, Mary, why don't we open it up for questions?

Thanks. Thanks.

Good morning. Just a couple of questions from me.

First how should we think of just your G&A in 2016? I know it's an all-in question, but it obviously in the oil price environment we're in, it definitely has a bearing on your cash flow?

Yes. Thanks Greg, appreciate that.

Yes. The way we look at it is similar to the rest of our cost.

We are very focused on reducing costs in all areas, and so whether it's field or Calgary that will be a focus.

Okay. But just to the broader level probably flat year-over-year?

Is it fair to assume that there will be some improvement there?

We're looking to continue to make improvements in all areas.

Okay. Okay.

Great. Second question is just with respect to your sustaining CapEx, can you dig a little bit more into that just in terms of perhaps what has changed when you released your budget.

I mean we used to talk about $225 million or so CapEx, and you're going to spend $170 million. is there, what is changing, is it a lot of the things you have already talked about, in terms of supply chain management, or are there some other things that you're doing to drive the number down as much as you are this year?

Yes. Thank you.

There's actually a lot going on right now. We are seeing, we have worked on the EM SAGP process, and I think most of the people on the phone would be familiar with it.

What we are finding is new ways to get further improvement out of that process. And so efficiency gains there, as well as efficiencies, improvements on individual wells are allowing us to really generate additional production at far less amounts of capital, because we don't have to go to new pads A, we can do it off existing pads.

Process improvements as well as the well performance and other improved performances that we're dealing with. So it was something that we started focusing on late last year, and we have been very successful in it, and as a result we're seeing it's allowing us to reduce the number of wells that we would need to replace the clients.

Okay. Great.

And let's just say we're in a high 50s or high 60s WTI price environment next year. The sustained CapEx sub 5, how much of that do you think could be preserved roughly into 2017 under that kind of prizing scenario?

In terms of the sustaining capital?

Yes. I'm just wondering if sub 5 or 5 to 6 now is the new norm versus what you talked about before of 7 to 8?

Yes. Let me go through that a little bit each year you assess what your decline rate is going to be, and that's a function of what the maturity of your wells are, and then on the other side of that equation you have process improvements occurring.

So each year is kind of a different look at it. We do see going forward that our Phase 2B is going to approach into 2017, the time period that we need to implement EM SAGP, and that tends to be a fairly lower cost approach to adding production volumes.

So we're rapidly heading towards that area.

Okay. That's great.

Thanks very much, Bill.

Yes. It's exciting.

We're really excited by it.

Hi. I was on the Suncor this morning, and there was a question of whether Suncor would be interested in maybe buying MEG, and CEO Williams said it was an interesting idea, and I was just wondering what some of your thoughts were our on that?

Well, we typically don't comment on those types of questions on the phone. Right now we are very focused on growing this Company, and we're extremely proud of it, and we think there's tremendous growth ahead of us so I would leave it at that.

Okay. That's fair enough.

Would there be any circumstance where you would consider maybe a merger or even an acquisition, given the low prices for some of the assets that are out there?

No. We're not contemplating that at this time.

Okay. Thank you.

Morning. Thanks for taking my call.

I guess it's a bit of a follow-up on Greg's point here. And that is I guess obviously you guys have done a lot on the operating cost front taking your costs down.

But if I look at your corporate charges, interest and G&A, I get $11 to $12 a barrel. I just wonder how much downside you guys see to that, and whether that's sort of where the focus shifts right now?

And that's it for me. Thanks.

I'm sorry. Could you just repeat that question louder.

I just couldn't quite hear you?

Yes. You bet.

So I guess if I look at your operating costs, you have guys have done a great job getting those down and they continue to fall. If I look at your corporate per barrel charges interest and G&A, and those are about $11 to $12 a barrel right now.

So I guess I'm wondering how much downside do you guys or whether you see any downside, and how much downside do you see to those, on then whether that's sort of I guess a logical place to focus your efforts going forward?

Yes. We focus our efforts on all of the costs and when it comes to the G&A if that's what you're referring to, it is a combination of where we do good work, whether it's field or Calgary, we find that and we're able to reduce costs in the field and in Calgary as well.

So we're going to focus on both of those areas. And I do think there are opportunities going forward in these areas.

Okay. Thanks.

I don't suppose you care to comment on how much?

No. At this time it would be premature to say that part.

Just the comment I would leave very clearly though, is that we are very focused on all of our costs.

Great, thank you.

Hi, Bill. Thank you for taking my questions.

I had two things that I wanted to seek your opinion on. First is regarding this maintenance that you plan in March, when was it originally planned, and how much will you save by bringing it forward?

The plant maintenance was originally planned into the second quarter, but we believe with low oil prices and everything, we could take advantage of these times and just move that forward, and so it's really just a shuffle from Q2 to Q1, but we think it's a wise move to do it right now.

Okay. And the second, and that would result in a curtailment of roughly about 8,000 barrels a day?

Yes. That's correct.

If it is all in the first quarter which we think it will be, but it will be towards the end of it, so we'll just have to leave some room for whether that straddles quarters.

Okay and the second question is with regards to the Access Pipeline sale, any details in that and what kind of interest are you getting, and is there a deadline for closing that deal?

Let me spend a minute on the Access Pipeline. So we are focused on monetizing that line, and it really is a key initiative for both management and the Board, and as I said in the past, the actual timing of that process is really dependent on commercial negotiations which can take some time.

The process though, I think it's worth while just sort of describing the process we're going through, just so people can get comfortable on it. It really is a multiple component process, so we start off with competitive bids, which is where we discuss and negotiate with the interested parties, that is typically a fairly large number of groups.

And then they have to do their due diligence, and then we get initial estimates on stuff. And then we go into the next round, and it's a smaller group that we're going to focus on there, and again, through a similar pattern.

But the last thing that I think is important to also realize that in the process that we're going in, we're not just monetizing the pipeline. We actually move from being an owner to a shipper, so what that means is that we have long-term shipping agreements that we also have to work through, and once all of this is together, then those are the elements that really form the final transaction.

So right now it wouldn't be prudent for me to nail down compact timing on anything, or be too specific because of the sensitivity of the timing of it. But I do think it's important that people appreciate that it really is a multi-prong process, and really those long-term shipping agreements are important to work through and get them right, because that's what protects value for the shareholder going forward.

Okay. And just a very quick follow-up on that, Bill.

Hosty [ph] is also selling some of its downstream interests including pipelines in the Lloyd area, but they are maintaining at least an equity there, and they are also asking for the right of their crude to be removed first. Is that something that you would be looking at with Access as well?

At this stage I couldn't really comment on it just because of the sensitive time. But we do look at what's right for the company overall, and we do make sure that we're working with the potential counter parties to see what makes overall sense.

Okay. Thank you very much.

Yes. Thank you for your questions.

Hi. I noticed that per unit energy operating costs increased sequentially, in fact it's the highest out of the four quarters, 2015.

Are there any reasons for that, and I understand there could be some seasonality issues?

So your question is on our per energy op costs for the quarter. Actually they're one of the lower ones for the whole time there, so just looking at our MD&A, and going through looking at those right now.

$358 per barrel?

Yes.

Versus in prior quarters like mid to, am I reading that correct?

No.

No. Unfortunately I don't think you are.

Yes.

Okay. Okay.

Sorry. I think the costs if I were to rattle them through Q1 they were 407, 371, 397 and 358.

Okay. Maybe I was miscalculating prior quarters.

All right. And then...

That one the cost associated largely with the cost of gas, and our steam oil ratio there. So our steam oil ratio has stayed fairly steady over time there.

Okay. Okay.

Thank you. And then just to clarify, because I couldn't find a good disclosure on that, are there any revolver maintenance covenants, and if so what are they?

No. Our revolver is very similar to our long-term debt.

It's all covenant light, so in other words there's no maintenance covenant of any type, and it is long-term as we say first debt not being due until 2020. So there is nothing that’s a financial trigger, or anything in those areas that could influence.

Okay. And regarding the asset sale of $110 million, I didn't find a more specific disclosure.

What were the exact quantification of the assets that were sold, either the acreage or the particular infrastructure?

By the nature of the agreement on the sale, we have confidentiality on it, the way I would describe it is it was a non-core asset, that we did not think we would get to for several years, and we felt it was prudent to take the opportunity to monetize that.

Okay. Thanks a lot.

Yes.

Hi. Thanks for taking my question.

I wanted to go back to what you said about in the event if sustained oil prices has the option to defer capital and at the reservoir and to natural decline. Can you give a bit more detail about how exactly you would do that?

Would it be a case of reducing the steam pressure, and how you would protect the reservoir against damage if it did go into decline?

Yes. It's a natural process.

I think you raise a good question. It's a natural process that reservoirs will decline in rates.

If you don't maintain the pressures on those. Now you can just increase the pressure and bring that back later on.

There are operational considerations that you have to manage, but we have managed those all of the way through shut-ins when we've looked at turnarounds and that. So we have been very successful in bringing those back, but you're asking the right question.

You think of these reservoirs as very prolific and everything, and they need the energy to put into it, to be able to produce the oil, but that is a readily source. I mean it's a source that we can quickly reapply to it, in the form of just adding steam back to the chambers.

And if it runs into natural decline what sort of rate of decline would that be?

Well, it's in the single digit area. It depends what phase you're at in different parts of the oil patterns, but that's an interesting comparison to what you might see with say shale oil, in the sense that they will see much quicker declines, and so I think as a general statement for the oil sands, it's a very positive statement.

These reservoirs can actually be kept at fairly flat rates of decline normally, and if you do go into decline, it's a very slow rate, and keep in mind the intention is to go there. That's just an option that we have in the event that our variable costs, in the event we couldn't cover our variable costs.

That's a huge advantage MEG has in the sense that our variable costs are probably one of the lowest in the industry, and as a result provides us with maximum flexibility there.

And can you just remind me what your variable costs are? I know it's in the results.

It's all driven off of price of gas and off of chemicals, and then that's offset by our revenues from power. So our variable costs would be sub-$4 dollars in that current world, but you wouldn't make a decision on a monthly basis or a daily basis this way.

You realize the way that our industry would approach it, is they have to believe that you would have long-term sustaining low oil prices that couldn't cover your variable costs, before you would go through that iteration and so that $4, less than $4 is Canadian. So that if you thought of it compared to US and what their alternatives are, it favors MEG and companies like MEG very, very well.

And I think in a more macro look at things, if you look at where the OPEC is doing, Saudi Arabia in shale oil and all of that. We are quickly as an industry getting ourselves positioned with lower and lower costs, that I think do give us an advantage over say the shale oils, because of the low decline rate, and because of the high recovery factors associated with these wells.

So it is a time that obviously in low oil prices is a tough time for our industry, but it's a very, very valuable time for an industry to really focus on getting itself competitive, and it has some natural opportunities there through the slow declines of our reservoirs, and the prolific nature of them.

Okay. Thank you.

Thank you.

I'm sorry. I had it on mute.

That would be problematic for me. Thanks for taking the questions.

I'm going to go back to kind of the sustaining CapEx that you guys were talking about. About how long can you kind of stay at those sub-$5 sustaining CapEx on your Brownfield’s, before you have got to kind of reach out, create some new greenfield expansions, and I guess kind of wondering looking forward past 2016 into 2017 and 2018 and even beyond that, is that 170 level still doable?

It is a function at the beginning there of the inputs that you have, or the supply options you have of crude. So in other words, it is something that we can see move through time, but you will see variations of it, pending what stage you are at with the reservoir.

So as I mentioned in 2017 our 2B wells are three years old. We think that they have enough heat in the reservoir at that stage, to be able to implement the EM SAGP, so what that does is it means that we can redeploy steam to other new wells.

Well those new wells don't decline for quite a while, and so you tend to have a number that will move around a little bit depending on the maturity, but there are a number of factors associated with the efficiency gains on the EM SAGP [ph] that are really helping us to keep those sustaining maintenance costs down. So just to be clear, it can move around year to year depending where your well life inventory is at, but we're continually redeploying steam to new wells that don't decline.

Okay. That's fair.

That's the only question I've got.

Okay. Thank you.

Hi. Thanks for taking the question.

Just want to know if you had any comments on the downgrade, and more importantly I guess, regarding the revolver. Any discussion with the banks regarding, are there any triggers such that you would be subject to a borrowing base?

Yes. I think that's actually one of the very unique things about both our revolver and our debt.

There are no triggers, there are no covenants, nothing that can trigger repayment or anything of that nature. And as far as Moody’s go, there's really no effect on our day to day operations or business.

We have been adjusting to the unsustainable low environment for the last 14 months, and we have been driving down our costs and ensuring that we have significant liquidity, and I think you can see that with the $400 million, and the undrawn $2.5 billion revolver with no covenants. So it positions us very well.

And on top of that with the long maturity of the earliest being 2020, as I say it positions us again to be able to go through this cycle in a positive way.

Sure. Thanks for the answer.

Then I guess last question, given your obviously very strong liquidity position, is looking at taking out some of the bonds which are trading at the 40s, is that an attractive opportunity given the yield right now?

Right now as we position ourselves to be able to it, we see that we have several options in this area, and we are exploring all options to see what makes the optimum sense to this. So there are a number, there is a lot of work going onto assess that right now, we haven't drawn any conclusions in any particular areas to the best way to do that yet.

Okay. So as of today you have not bought back any debt?

That’s correct.

Okay. All right.

Thank you. That's all I had.

Yes. Thank you.

Hi. Thank you.

One question for me, back on the Access Pipeline. Are there any conditions or factors that would cause you and the Management Team, the Board, not to monetize the pipeline?

Obviously the one thing that we have to look at is overall, is just what's in the best interest of the corporation and the shareholders. We are very focused on doing that, but we have to strike the right balance on things.

So if you saw the oil market recover faster than you expected, there could be a possibility to keep that for strategic reasons?

I don't want to speculate on the price part of it, but we're focused on the idea of actually monetizing it right now, we think there that there could be a right equation in there that could be in the interest of our shareholders in the monetization of it. And so we need to get it right overall, but it is the focus of what we're doing, and because we're spending so much time on it, we do think there are opportunities to monetize and keep the strategic nature of it.

Okay. Thank you.

Yes.

Hi. Can you talk a little bit about how you're sort of interest in the pipeline has changed over time?

Obviously you have been marketing it for a while now, and we have seen a pretty significant dislocation in the MLP space more recently. So are you seeing different interest from bidders?

Have you had anybody who might have been involved earlier in the process and then backed out of the process? Any other color you can provide on that?

Obviously, the sensitive nature of this right now, we can't give a lot of details on it. I can say our process is progressing as we expect it to, so we are moving forward, but because of the sensitive nature of the timing, it wouldn't be prudent for me to really comment on that.

Okay. That's fair enough.

And then just switching gears to the sort of, if you decided to do shut-ins around your variable costs. So are you to put it in simplistic terms, are you saying that basically shutting in production due to it being uneconomic is similar or the same to what you guys have to do when you do turnarounds in maintenance or are there some different considerations giving maybe a longer time frame that the production would be shut-in, or anything like that?

Well, first of all, the first approach we would be talking about is reducing our sustaining and maintenance focus on it, so that would be freeing up more cash that would have been spent towards drilling wells. So that is a step that's behind just operations.

Like I mean right now, we are recovering our variable costs and moving towards covering, contributing significantly to our fixed costs. So that is a what-if behind that, and then if you went further and you actually decided to shut-in certain areas.

What you have to do is make sure that you manage that reservoir if you were to shut it in, but that's a long ways away from what we're thinking right now, I don't want to lose the focus that we are very positive on our position as a low cost producer covering the variable costs, and then having additional costs towards the fixed. But as I say as the reservoir management process, you don't just shut-in wells, you would maintain and monitor and do the right things to protect that reservoir, if you ever got that far.

Okay. Can I just ask one question on that?

If you have a CapEx level that if you stop drilling new wells and then went into that low single digit decline that you would be at?

I don't have one off the top of my head, but obviously you would take the sustaining maintenance component out, which is the large amount of those dollars that remain in that $170 million.

Okay. That's all I had.

Thank you.

Yes.

Thank you.

But it does show, it's a good illustration of the flexibility of the system in a low part of the price cycle, and I think it comes from the strength of the low cost position that MEG has got itself in with its operating costs. Okay.

Thank you.

Yes. Hey guys.

Bill, you mentioned in and certainly appreciate the sensitivity on this, considering your process on Access, but just curious if you can give us a little bit more color as to where you are on your process? Obviously you said it was multiple components to it.

Are we closer to the front end on still negotiation and signing NDAs, or have you been able to get closer to shrink-the-group phase?

Obviously I have to be very careful in answer to that question, so I would say that we're pleased with the progress we are making, but I really can't say at this time. I think it's too sensitive to discuss that.

Okay. Thank you.

Thank you.

Great. Thank you Mary, and thanks everyone for listening in on our call.

Helen and I will be around after for any follow-up questions you may have. Other than that, thanks again, and everybody have a good day.

Thank you.