Tourmaline Oil Corp.

Scott Kirker – Secretary and General Counsel Mike Rose – President and Chief Executive Officer Brian Robinson – Vice President of Finance and Chief Financial Officer

Fai Lee – Odlum Brown Elsie Ross – Daily Oil Bulletin David Phung – Credit Suisse Thomas McGannon – Whetstone

Thanks, Melanie, and welcome everyone to our discussion of Tourmaline's 2015 Q4 and year-end results. My name is Scott Kirker.

I'm the Secretary and General Counsel of Tourmaline. Before we get started, I'd refer you to the advisory on forward-looking statements contained in the news release, as well as the advisories contained in the Tourmaline Annual Information Form available on SEDAR.

I'd like to draw your attention in particular to the material factors and assumptions in those advisories. I'm here with Mike Rose, our President and Chief Executive Officer; and Brian Robinson, our Vice President of Finance and Chief Financial Officer.

Mike will start by speaking his highlights and after his remarks; both Mike and Brian will be available for questions. Go ahead, Mike.

Good morning, everybody. Thanks for dialing in.

Tourmaline is pleased to release 2015 financial results from yesterday and coupled with our reserve release of two weeks ago, reiterates how strong our 2015 performance was. We grew reserves by 30% and production by 37%, and did sold profitability.

Some of the highlights: Q4 earnings were $34.6 million, and again that underscores the fundamental profitability of our EP business even in a very low commodity price environment. Full-year earnings were just over $80 million.

Q4 cash flow was $242 million, and that was up 23% over the previous quarter Q3 of 2015. Our all in cash costs for 2015 were $7.56 per boe, so operating transportation, G&A and financing and that was down just over 5% from 2014.

Q4 OpEx was $4.23 a boe and our 2015 cash G&A costs were $0.45 per boe, and that was well ahead of target. And we will continue pursuing all possible cost reductions in all aspects of our business.

Fourth quarter 2015 production of 179,610 boes per day was up 37% year-over-year and almost 20% over just Q3 of 2015. And the full year average production of 154,403 boes a day was up 37% year-over-year or about 29% per diluted share.

On the reserve front, our 2P reserves as we’ve previously released increased to 1.108 million boes by the end of 2015 and that was a 36% increase or 22% per share prior to taking into account annual production. Total proved reserves were up 48% and PDP reserves up 80% on a similar basis.

After seven years, Tourmaline has 1.1 billion boes of low cost, economic reserves and we currently produce over 1 bcf a day of natural gas and over 25,000 barrels per day of oil, condensate and NGLs. So we broke the billion barriers on both fronts.

Capital efficiencies in 2015 were approximately 15,500 boe per day and that’s a 26% improvement over our 2014 performance. Our 2P total proved and PDP, FD&A costs were record lows for the company.

We estimate that our 2P reserve based NAV, PV10 before tax at year-end 2015 was $37.26 per share and that was less than 10% of a very well-defined future drilling inventory of over 12,000 locations booked. Moving to the EP capital program, we’re reducing our full-year 2016 CapEx to $775 million.

The original budget and [indiscernible] down previously somewhat was $1.1 billion. And that $775 million is inclusive of any acquisitions done in 2016 and we’re doing that obviously because of the low commodity price environment that we’re all in.

First half 2016 EP spending of $350 million continues as planned and that was announced previously and we will work maybe to come in a little under that. And the second half EP capital program has been reduced to $275 million.

The second half program will essentially be directed entirely towards drilling and completions with a minor amount of capital for tie-ins. Full-year 2016 production guidance remains unchanged at 200,000 boes a day as very, very strong individual well performance and inherent production efficiency gains, allow us to do so.

Additional new facility expenditures are not required to meet the 2016 and 2017 production plan, so more and more of the capital directed to just drilling and completions. The 2016 capital program is the cash flow budget as originally planned.

We’re currently forecasting full-year 2016 cash flow of $791 million. And we will continue to watch the commodity price outlook and make adjustments to the full-year capital program accordingly.

We reduce the rig fleets from 12 at the start of the year in January. We’re currently operating one rig.

We plan to operate one to two rigs on an intermittent basis during breakup or this second quarter and currently plan seven or eight rig program in the second half of the year, but again that’s commodity price dependent and it’s all, so that we stay on budget. We have completed some minor non-op dispositions and then they just simply further strengthened in the balance sheet.

Our exit 2015 debt was $1.55 billion and we forecast that to stay flat or slightly down by exit 2016, so current projection exit 2016 is $1.52 billion. Moving to the cost side of the business, we had a great year reducing both capital and operating costs during 2015.

Our drill and complete capital costs have been reduced by approximately 25% across all three operated areas year-over-year and we are targeting a further 10% reduction in capital costs in 2016 and believe we’ve largely achieved that already. All in cash costs in the fourth quarter of 2015 were $7.13 a boe and that’s our lowest in our corporate history.

Q4 OpEx was $4.23 a boe, so slightly lower than guidance and we will keep chipping away at all components of the cost equation. G&A cash costs were $0.45 a boe in 2015, so below guidance of $0.60 a boe, so we brought down our full-year 2016 G&A and our projections to $0.50 a boe.

We have kept our staff count low all along, so fortunately we haven’t had to contemplate any reductions on that front. Moving to the EP program, as mentioned before, capital efficiencies on the EP program in 2015 were 15,500 per flowing boe and that’s our best yet.

And that’s also inclusive of $491 million of facilities capital spent in the year. So we anticipate our production efficiencies in 2016 to continue to improve because that we’re only at the current time planning approximately $100 million in facility and pipeline expenditures in full-year 2016.

Production performance in Q1 of 2016 has been very strong. We’re ranging between a 190,000 and 205,000 boes per day so far, so ahead of forecast, and we’ve also got a few more wells to tie-in before we shut it down and break-up.

Looking at Northeast BC, Montney production reached a record 55,000 boes a day during the first quarter. We’ve got three large multi-well pads to frac during the second quarter, and so we will keep that facility network in BC jammed full.

We expect a further production growth in BC of 10,000 boes a day in the first quarter of 2017 and we’ve moved our Doe facility construction project into Q1 2017 out of the second half of 2016. And then after that our large Sundown gas development project will provide significant growth in 2018 and beyond.

Moving to the Alberta Deep Basin, our Wilrich and Notikewin sweet spot program with multi-well pads continues to deliver well performance well above our economic template. The 30 day average IP for our Deep Basin horizontals over the last four months has been 10.1 million per day, so double what our forecast 30 day IPs are and that’s over 46 horizontal wells and that’s up over the previous period.

As announced in February, we closed the acquisition of key Wilrich and Notikewin sweet spot assets in the greater Edson-Ansell-Minehead area and that added approximately 48 million boes of new reserves that weren’t in our year-end 2015 report, net of dispositions about 4,000 boes a day of new production and over 100 incremental high-performance high EUR sweet spot drilling locations. We now have the new volumes from that acquisition connected into the Tourmaline facility network and that significantly reduces OpEx of that new production stream.

And of note, the first step-out to the very high rate Notikewin well that we announced Q4 50 million a day, and that’s the 2-27 well. So the step-out tested just at our last week of 47 million a day at a flowing casing pressure of 32.5 MPa and that was on a three-day test.

And there are multiple additional follow-ups of Notikewin. And then, of course, we’ve got the Wilrich sweet spot to develop.

Much further to the north, but still in the Deep Basin, the Smoky 12-30 Wilrich horizontal, very strong well, 39 million a day at casing pressure of 13.1 MPa. And that well is in a very large Wilrich sweet-spot in the Smoky-Horse-Leland area that we’ve been developing two to three years, so a lot more to come from that part of the Deep Basin.

Kind of note, we’ve also realized material increase in our future drilling inventory through the course of 2015 due to new place, new discoveries, successful delineation drilling. We’re now up to 12,350 locations, and we’ve booked less than 10% of those in the year-end 2015 reserve report.

So, a lot more reserve in production growth to come. And that’s all I was going to say formally.

So Brian and I and Scott are willing to answer any questions you may have.

Melanie, I’ll turn it back over to you.

Hi. I’m Fai Lee here.

I’m just wondering in terms of the 2016 production guidance, what sort of base decline rate are you reflecting in that guidance right now?

Fai, it’s 34%.

34%.

Yes.

And you ended 2015 with almost 180,000 boes per day at the Q4 production average. What are we looking at in that production guidance for Q4 2016?

Q4 2016 is 209,000 barrels of oil equivalent per day, which is comprised of about 15,000 barrels of oil and condensate and 14,000 of NGLs and then one – almost 1.1 billion a day of gas.

Okay, all right. Now, I was looking at today’s presentation, you have talked about capital efficiency of 12,000 to 13,000 boes in 2016.

And I can fall offline, but I’m just looking at based on your 34% decline rate, if you – that’s almost like about 60,000 boes, but you’re spending $775 million using that 12,000 to 13,000 capital efficiency, almost down [indiscernible]. So I am not sure there maybe something missing?

Well I think the well performance is actually a little better than what we’re forecasting, so that helps with the efficiency of that plus you’ve gotten no facility expenditures.

Right. And then recall that we do have 17,000 barrels of oil equivalent behind pipe and we will be deploying that throughout the course of the year to keep our infrastructure full.

Okay.

You're right that the flowing barrel number should come in like it will be closer to 10,000.

Okay that’s what I’m trying to figure out. Okay.

That makes sense. Thank you.

You bet.

Hello. Thanks for taking my question.

I'm just wondering what you're seeing for acquisition opportunities in your core areas. Given that you guys are in a pretty good financial shape and I am just wondering a lot of other companies aren’t.

And so I am just wondering if you’re seeing the opportunities for acquisitions, even maybe it might be a little cheaper to buy some production and then maybe go for it?

Yes, I think, everything you said is true. I guess even if you're in stronger financial position, which we are, we want to execute the cash flow budget, so we don't have a lot of extra money either.

And then alternatively is there anything that maybe you'd be looking to maybe let go like a lot of companies are letting some of the infrastructure, the midstream or anything like that?

Yes, we’re not finding to sell our midstream. We have been pretty good about moving out minor non-op assets.

We did some already in Q1. We've got a couple of other small things we might move, but nothing material.

Okay, thank you very much.

Thank you.

Hi. Just to ask questions here.

You’ve got those operating down cost, really significantly, all across the board. Are there certain things you’ve been able to do that helped you accomplish that apart from your own – facilities you own?

Well most of it comes from systematically getting all our gas production through our own gas plant network where we – our OpEx is $0.15 to $0.20 per mcf and that’s probably the biggest piece of it all. Brian?

Well, and then the other piece is that we cut down our Mulligan network working fully where we’re – mid-year we were using temporary factories to process our oil, so that helped us a bit. And the third piece is we’re bringing on a lot of really high rate wells, which inherently you’re going to have lower unit cost.

Okay. Thank you.

Hi, good morning. I am just wondering if you guys…

Sorry, we couldn’t hear that.

Do you guys report the corporate average for liquid use for 2015?

Corporate average for liquid use…

Sorry, could you repeat that. We can’t hear you.

Oh, we’re just wondering if you guys report the corporate average for liquid use for 2015.

The liquid yields…

Yes.

You mean our net back on our NGLs?

Not the price, but the ratio like…

Oh, the comp position. So, the way you can think about that is rough – it’s – buy us to little bit to ethane because we’ve been running some gas through the [indiscernible], but overall it’s about equal amongst all the components of pentane, propane, butane and ethane with a little bias towards ethane.

So, will you say it’s more like – the barrels per mmcf…

Oh, barrels per mmcf, so in the Deep Basin, it’s between 15 and 20 barrels per million and in our Montney project, it’s between 30 and 40 and then we also have our Turbidite load, which is condensate rich on top of that.

Okay, thank you.

Thanks.

Good morning, guys. A quick question.

In your guidance, have you taken any disruptions from TransCanada and just give us if you’re seeing anything coming down the pipe or disruptions there?

So far 2016 has been a lot better than 2015, so in 2015 our average production for the full year was reduced by 7500 boes a day because the firm service curtailments. So far in 2016 a lot less, so it’s – we’ve got about 2500 boes today built-in for disruptions in 2016.

Okay. And on your capital number of $610 million, I think it was noted that was at the low end of your maintenance budget.

What was the high-end of that range?

$700 million.

Okay, great. Thanks guys.

You bet. Thank you.

Hi, guys. I apologize if this question has already asked.

I got interrupted earlier. Hey, so, when I look at the strip right now, I am seeing like a $1.88 against your $250 million guidance for the year.

So maybe if you could help me understand, is there some kind of heat content uplift that we needed to be thinking about that bridges closer to that guidance? And then if not, do you guys have any stocks on how you may adjust the capital plan if the strip holds I guess?

I mean, first off, it’s a good question, but when we come up with our gas price for the full year which we just went through with our board, we look at nine different data sources. And so we don’t just look at the strip, so we’ve got a whole array of sources.

They come from GLJ, Deloitte, and then the range of banks that are Canadian banks, so we just take the average of those. So we came up with this 255 number that you see in there.

We do get a heat content list. We baked all that in of course.

It’s about 7% or 8% at the moment. And then we’ve got our hedging program.

And in there we’ve got about $130 million on swaps and then about another $170 million where we’ve got the AECO to NYMEX basis protected. And yes, we are above the strip and it’s because we believe that in fact gas prices will rally throughout the year as we see receipt slip off a little bit here in the Province of Alberta.

And so, I think it’s – in our judgment it’s a more realistic price and perhaps just relying on the strip which changes on a daily basis.

Yes, and then to complete that and we say it in the press release, we will continue to monitor commodity prices and adjust the CapEx accordingly.

That’s great. And then maybe just kind of a follow-on to the basis topic, longer-term, how are guys thinking about your gas price basis to Henry Hub as you see more Northeast connectivity into the upper Midwest?

Yes, sorry, go ahead. So, I mean, we run gas on all of the major systems than northern border alliance, TCPL, Nova, and then Spectra system.

And so we try to tap into it with many markets as we can. In our judgment, when we can get in this $0.50 to $0.60 range on the basis and keep it there for term that that’s a good trade for us.

We’re also going to start taking gas into California here in August at a place called [indiscernible]. So, our view is that the gas out of that Marcellus basin isn’t going to make at all the way through into the Chicago area anytime soon, so we’re going to continue to look at the market the way we do and we think that there will be periods where the spread blows out a bit, but generally we think that that’s kind of where we’re going to see it.

All right, great. Thank you, guys.

Thanks.

Thanks, Melanie, and thanks everybody for attending our conference call. We will talk to you in the next quarter.