MEG Energy Corp.

John Rogers - Vice President, Investor Relations and External Communications Bill McCaffrey - Chief Executive Officer Eric Toews - Chief Financial Officer

Greg Pardy - RBC Capital Markets Mike Dunn - GMP FirstEnergy Gary Stromberg - Barclays Papa Chakravarthy - Columbus Hill

Thank you, Marianne. Good morning, everyone and welcome to our third 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 review the results for the Q3 and Bill then will take a look forward outlining your strategy to grow and delever the company.

I will remind you that today’s call contains forward-looking information. Please refer to either our quarterly reports or other documents such as are on SEDAR or our website for further information.

And with that, I will turn it over to Eric. Eric?

Thanks, John and good morning everyone. As John indicated, I will start with an update on our operating and financial performance over the past quarter.

Q3 was a solid quarter for production, which averaged 83,404 barrels per day. This production level is slightly over our annual production guidance, the continued implementation of technologies enabling us to see transformational results for the corporation.

We have grown our production, at the same time, reduced our 2016 planned sustaining capital to below $5 per barrel. You may recall that the original capital budget for 2016 was $328 million with the focus on sustaining production and capturing efficiency gains through the EM SAGP process, we are now able to reduce our capital budget to $140 million in 2016, while maintaining our full year production guidance of 80,000 to 83,000 barrels per day.

These efficiency gains have also enabled us to reduce our year-to-date per barrel non-energy operating costs by 44% since 2011 and 27% since 2014 to a record low of $5.33 in the third quarter. As a result for the second time this year, we are reducing our 2016 non-energy operating cost guidance to $5.75 to $6.50 per barrel from our previous guidance of $6.75 to $7.75 per barrel.

Our cost reductions have been made possible because of the way we have revised our business model that relies on our proven proprietary technology. This has enabled us to reduce our overall headcount by 40% since late 2014, which had the effect of reducing our year-to-date per barrel G&A costs by 22% for the same timeframe to a record low of $2.94 per barrel in the third quarter.

In total, we have reduced our G&A costs per barrel by 41% since 2011. We believe these cost reductions are largely sustainable.

In time, as we increased our production, we will spread our fixed non-energy cost G&A and interest over more barrels, which will further reduce our per barrel cash costs. Efficiency gains from technological improvements and outright cost reductions have also allowed us to reduce the price required for our cash flow after all corporate and interest costs to breakeven at $42 to $45 WTI per barrel compared to approximately $50 per barrel last year.

This helped generate cash flow from operations of $23 million in Q3 which was sufficient to cover $19 million of capital investment during the quarter. Let me take a moment to talk about mixed financial position.

At the end of the third quarter, we had a cash balance of $103 million after taking into account cash flow capital spending and semiannual interest payment on our long-term debt. At current strip prices and with a capital investment of $140 million for the year, we expect our $2.5 billion revolver will remain undrawn at the end of 2016.

We have been using a hedging strategy to protect our near-term cash flow against volatility in crude oil prices. As of the end of September, we have hedged the WTI component of our pricing for more than a third of our blend sales to the end of 2016 and a quarter of our blend sales in the first half of 2017.

We have also hedged more than 40% of our condensate purchases through to the end of 2017. Make strong financial liquidity along with its well structured debt and its ability to maintain operations with very low capital investment continue to be the defining attributes of the company.

With that, I will pass it over to Bill.

Well, thanks Eric. The utilization of technologies enabled us to make significant strides in our business over the last couple of years reducing our overall cash cost saves while allowing us to be successful in a lower oil price environment.

Going forward, we have the opportunity to advance our use of technology through the development of high return short cycle projects that will further reduce our cash cost, while adding meaningful cash flow. These growth opportunities in combination with the focus on absolute debt reduction via the potential monetization of the pipeline will allow us to continue with the strengthening of our balance sheet.

Our overall objective is to optimize the company’s financial position when we come to renegotiate our outstanding debt, which is not due until the end of the decade. We are continuing to expand the use of our proprietary technology to significantly improve our reservoir efficiencies, which allow us to drive sustainable cost reductions.

Where we have already implement EM SAGP, we have increased production with less fee to the use of infill wells and new SAGD well pairs and cut our steam-oil ratio by one half. Our overall greenhouse gas emissions intensity is currently 30% below the industry norm and has the potential to be reduced even further.

We have dramatically reduced our capital and operating costs per barrel and reduced the time required from investment to cash flow. Equally important, our technologies give us the potential to increase recoveries by an incremental 10 percentage points from 60% to 70% which helps lower our overall sustaining and maintenance costs.

To-date, we have acquired EM SAGP to about 25% of our production. Having proven this technology, we are now ready at the right time to expand the EM SAGP partially or fully to our Phase 2b wells, which represents the remaining 75% of our production.

And this illustrates the tremendous flexibility of our business plan. Once complete, we expect to see an increase in production of 20,000 barrels a day.

Due to the nature of our cost structure which is largely fixed, we expect that the incremental production will result in continued decrease in the overall cash costs of the company. And the capital intensities of $15,000 to $20,000 of flowing barrel, we anticipate that the projects will generate a return greater than 30% at $45 a barrel.

In addition, the implementation of the Brownfield expansion on Phase 2b has the potential to add another 13,000 barrels a day to the overall production. Together, these projects offer some of the company’s best returns to-date and will help to further drive down our cash costs.

And we believe there is more to come. We are also in the early stages of investigating an increase in the benefit that we received from EM SAGP by its new consultants to the process.

This has the potential to further reduce the steam-oil ratio as well as our cash costs. As I mentioned earlier in combination with the growth, we are also focused on reducing our absolute levels of debt to strengthen the balance sheet.

And to achieve that goal, we will continue to work and settle the pipeline under the right conditions. It’s difficult to get the right value during the low level price cycle, but as oil price improves, we remain focused on getting a value that strikes the right balance between the upfront price and the ongoing cash cost impact associated with such a transaction, while still protecting the long-term interest of their shareholders.

MEG has made considerable progress since the start of this commodity pullback 2 years ago. Leveraging off the efficiency gains, we have increased our ability to sustain the business through low oil prices by reducing the WTI at which cash flows breakeven by greater than $5 in the last year alone.

Going forward, we anticipate that further application of technology will enable us to continue to reduce our costs by changing the way we operate and grow. We believe we can and have sustainably reduced the cost structure of our business putting us in an even stronger position to successfully compete on a global basis.

And with that, I will turn it back to John.

Well, thanks, excuse me, thanks Bill and Eric for your remarks. So, Barry, we are going to open the lines up for questioning.

As a reminder, we would like to keep the questions in respect of all the people on the line to the strategic level. Of course, Helen and I will be around after the call to answer any of your modeling questions that you may have.

So with that Marianne, why don’t we open up the lines for questions?

Yes. Thanks.

Good morning. Really, just one question I had is with respect to the capital program this year, so the spending came in probably half of what we were expecting in the third quarter.

And then if I think about your cumulative spend for the year, call it just under $75 million against $140 million budget, is it that there is a fair bit of planned maintenance that you are going to need to do in the fourth quarter or is it also possible that you would still have some dollars left over to start to proceed with growth initiatives, I am just trying to think about how I should think about your capital program this year?

Sure. Thanks Greg.

Yes. In the fourth quarter we are going to be doing some sustaining well developments in order just to maintain our production levels.

So we would see some additional capital as you would expect in that area. We are very pleased to mention with the ability to reduce the capital that we have this year and that’s largely due to the efficiency gains associated with the EM SAGD process.

And so we believe $140 million is a good number. However, obviously, we are well on track to hitting that number.

But we do need to think that fourth quarter will have some additional sustaining wells in order to maintain…

Okay, perfect. And when should we expect just your plans to be unveiled for 2017, is probably December, January?

Yes. I would think this in December right now.

And what we are looking at is just the macro conditions out there right now. I am just trying to understand [indiscernible] as I am sure everybody else looks well right now?

Okay, thanks very much.

Thanks, Greg.

Question for you is when you consider the potential to sell access along with Devon, what type of a tariff would you have incurred on a per barrel basis that maybe deal look less attractive from your perspective?

Well, thanks on that. I really can’t go into the details of that particular one here.

But the way I would look at it is that you have got to make sure that on this type of pipeline you get an upfront value and then obviously, there is a commitments on that pipeline, And you have got to make sure that the cash that you will pay – you will put out as part of commitment going forward makes sense for the company. Now the things we have to watch very carefully is that we are continually driving down our cash costs per barrel, so that we can compete at lower prices.

And so we have got to strike that write-down between what that number will be and with the upfront proceeds, obviously like there is much upfront proceeds as you can, but there is a cost and that cost is the total infrastructure. So that’s why we are being very disciplined on this.

We need to protect our shareholders’ interest in this area.

Got it. Thank you.

And then just as a follow-up, as it relates to the potential to expand, I mean if you would have looked at grow production by 20,000 barrels a day using I guess that will be about – at the high end of your guidance would be about $400 million cost, what’s keeping you from doing that now, I thought that you had suggested earlier in the year that you would consider selling equity to fund that, it does seem that the equity market would like to see the de-leveraging, so are you really just waiting on commodity prices to make that decision or is it still on – in consideration at this point?

Yes. Thank you on that.

What we are focused on is in this area is just making sure that we have got a number of options on it, but we do look at the macro conditions right now to see where we think prices are going in that. And we are being disciplined.

Our focus is mostly on cash preservation and balance sheet and that – and we want to make sure we really do understand what’s that being on a macro sense. What I have described today in the script and everything is very exciting.

We are ready to go on it, but we do need to see that we are comfortable on an macro level. And we do have a number of options in terms of moving that forward.

Thank you.

Thanks and good morning everyone. My question is relates folks to maybe if you could give us a sense of how many well pairs were sustaining production, you are likely going to be drilling this year and how that compares to next year, I do understand that with Phase 2b, now a couple of years into it here you are going to have to drill more sustaining wells next year, but I also I think that maybe you have some options there in terms of maybe using some EM SAGP volumes in place of adding well pairs, but maybe just some commentary on really what I am getting to is the range of what’s sustaining capital might look like next year relative to this year?

Thank you.

Sure. We are just putting those strategic numbers together, but I will give you some ideas on our thinking behind that.

So what we do is EM SAGP is obviously working out exceptionally well for its company. And what we typically do is we look at it in probably about a 2-year or 3-year period warming up the reservoir and then we convert it into EM SAGP process.

What that does is it allows us to free up steam to redeploy it to new well pairs. And what we want to do when we are looking at it is get that right mix of infill wells and SAGD well pairs going forward just to continue to keep the sustaining costs down.

Now, then we will vary a little bit from year-to-year but and striking that balance between infill wells and SAGD well pairs we can manage that. And as I say right now, we haven’t actually concluded our 2017 budget, but those are the factors involved in.

Okay. Thank you, Bill.

Yes. Thanks Mike.

Hi, good morning. Just a question on – I think I heard $45 breakeven mentioned in the script, just wanted to confirm that and then maybe if you can talk about some of the assumptions behind that production levels, maintenance capital differentials and how sustainable that is over time?

Yes. Sure.

Yes. The costs right now breakeven costs was about $42 to $45.

And I think what I do rather than throw all the numbers around right now I will let you talk with Helen and Peter on it. So think of it though that our breakeven – I said Helen and Peter – I swear to that, I mean, Helen and Don.

The – I think of it right now as our breakeven costs are about $42 to $45. And then as we add infill production – I am sorry EM SAGP production in that project that will further reduce those costs.

And what we are really doing is spreading fixed costs which are largely non-energy and that’s probably about 85% and an interest in G&A over more barrels, we do think there is significant opportunity to further – to lower those costs further.

Gary, when we come up, it’s John Rogers. When we come up with $42 to $45, it’s basically a calculation that we do from the previous quarter that we have just had.

So the actual assumptions that we actually aren’t making any assumptions and that calculation is based on the date that we actually had and present to that quarter. So when we came up with the $42 to $45, it was based on the third quarter results that we have…

And that’s inclusive of maintenance capital, right?

Yes, it is. Yes.

Okay. And then just second question is on diluent…

Gary, I did not answer that – that is before sustaining maintenance, sorry. So you have to include sustaining maintenance on top of that.

Yes, this year’s sustaining maintenance is below $5 a barrel, so you would go $42 to $45 plus that $4 to $5 sustaining costs.

Got it. And then just second question on diluent, it looks like diluent usage is coming down and costs of diluent obviously coming down.

Is that sustainable? And can you talk about what’s happening there?

Sure. Yes, what we do is we did about half of our condensate from the Gulf Coast and we are very opportunistic over the last little while to look for opportunities with condensate is low in cost.

And that’s where some other hedging comes in and we mentioned that we have a meaningful portion of our comments hedged all the way through 2017. And that’s because they have got a very efficient way of bringing new condensate up in the Gulf Coast on pipeline and it works very well for us.

And the Gulf Coast markets are the most liquid markets for condensate. So, as you pay close attention, we are finding ways and you can see it in the results to reduce that condensate cost.

Okay, great. Thank you.

Hi, guys. Thanks for taking the question.

Just one more piece of clarification on that breakeven number that you cited, is that burdened with G&A and interest as well?

That’s a good question.

Yes, that is a really good question. That’s important question, because sometimes people quote those numbers differently, you will hear a breakeven and they might be talking about the well costs or operating costs.

That’s our corporate breakeven. So, our operating costs are considerably below that.

So, Papa, it does include G&A and interest, yes.

Yes.

Great. Thank you, Marianne and once again thanks everyone for listening in and those of you who asked questions, thank you for those.

Helen and I will be around to answer any of your other questions that may come up as you think to report. So, once again thanks and everybody have a good day.

Bye now.