Tourmaline Oil Corp.

William Kirker - Secretary & General Counsel Brian Robinson - VP, Finance, CFO & Director Michael Rose - Chairman, President & CEO

John Green - TD Securities Michael Shannon - Hill Park Holdings Fai Lee - Odlum Brown Limited

Thank you, operator, and welcome, everyone. To our discussion of Tourmaline's 2017 Second Quarter Results Conference Call.

I'm Scott Kirker, and I'm the Secretary and General Counsel for Tourmaline. Before we get started, I 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, Tourmaline's President and Chief Executive Officer; and Brian Robinson, Vice President, Finance and Chief Financial Officer.

Mike will start by speaking to some of the highlights of the quarter, and after his remarks, we'll be open for some questions. Mike, go ahead.

Good morning, everybody. Thanks for dialing in.

We're pleased with our strong second quarter 2017 results. Starting on the financial side, second quarter earnings were $109 million or $0.40 per share, underscoring the continued fundamental underlying profitability of Tourmaline's EP business across all three core complexes.

Our second quarter cash flow was $313 million and that's up 133% or 100% per share from Q2 2016 cash flow of $0.58 per share. Op costs in the second quarter of '17 were $3.22 per BOE and that's down 6% year-over-year, and of note, ahead of our full year OpEx guidance, which was $3.60, we've taken it down to $3.50 per BOE now.

First half '17 cash flow was $606 million and that's more than double of first half 2016 cash flow of $294 million, and of note, greater than our first half capital spending of $589 million. We generated just over $17 million of free cash flow during the first six months of '17.

Our net back in the second quarter was $15.36 per BOE and that's a 78% improvement year-over-year. And total cash costs for the quarter were $7.10 per BOE and that's amongst the best in the sector.

On production, Q2 production of 235,540 BOEs was up 27% over Q2 2016. We've continued our strong liquids growth, Q2 '17 liquids production was just over 36,000 barrels per day and that's up 60% year-over-year.

And of note, our liquids production in June was just about 39,000 barrels per day, so very close to the 40,000-barrel per day milestone that we were targeting for Q4 of this year. So a little ahead of schedule.

And the company continues on track to achieve its full year 2017 production guidance of between 240,000 and 260,000 BOEs per day. That will represent 30% year-over-year growth and we'll accomplish that with a cash flow budget.

And we anticipate reaching the 250,000 BOE per day milestone later on in the second half of August. Moving to our continuing cost control; the company continues to seek all opportunities across the business in all three core areas to reduce capital and cash costs.

Second quarter 2017 OpEx at $3.22 per BOE is a highlight. We did complete and tie-in our company interest power generation facilities and systems on the Peace River High.

We also doubled the capability of the Spirit River 3-10 Sour Gas injection plant, and that will lead to significant further cost reductions in the Peace River High complex during the second half of this year. And remember that the Peace River High oil complex can generate a full cycle return to shareholders at an oil price of $25 per barrel U.S.

WTI, so one of the lowest costs oil resource plays in North America. On the drilling cost front, at Gundy Creek, drilling costs are averaging between $1.5 million and $1.7 million per well over the first 12 wells and that's approximately half that of the previous wells that were drilled on the property during 2014.

On our 2017 capital program, first half capital spending was $589 million, and as pointed out, less than cash flow as we are on cash flow budgets with the EP program for '16, '17 and going forward through the five-year plan. The full year 2017 capital program remains unchanged at $1.3 billion.

Our Q2 '17 exit net debt was $1.6 billion, down quarter-over-quarter from $1.7 billion at exit Q1 '17, yielding a forecast annualized cash flow -- net debt to cash flow of approximately 1.2x, and that's where we expect our exit 2017 debt to cash flow to be as well. We did make some modifications to 2018 and the full five-year plan.

We have elected, at our choice, to moderate capital spending and production growth in '18 and the '19 to '21 period. Annual production growth in 2018 will be modestly reduced from 22% to approximately 15%.

And then, production growth in 2019 to '21 period has been moderated to 10% per annum. The net result of these changes is to accelerate free cash flow forward in the plan and continue to improve our overall returns.

And we just believe that this is a more appropriate pace of growth in the current commodity price environment that we see for '18 and '19. The 2018 EP capital program has been reduced from $1.79 billion to $1.52 billion.

And average annual production, the range is now 280,000 to 300,000 BOEs per day, down slightly from the previous range of 290,000 to 320,000 BOEs per day. Our free cash flow in 2018 increased to $208 million from $50 million previously, utilizing the same flat commodity pricing that we've been employing in the plan.

The main revision to the '18 EP program is a deferral of the startup of the Gundy Creek facility by approximately nine months from Q4 '18 to mid-2019. The Gundy Creek deep cut gas plant is being designed for 200 million per day capability, but the Montney reserve base and the existing location inventory on the property actually support a flat 400 million per day production level for over 20 years.

So components of the plant design and the infrastructure build-out will be put in place to facilitate a potential down-the-road expansion from 200 million to 400 million per day. But in the five-year plan, that plant is going in at 200 million per day on the production side and the associated capital to build a plant of that size.

And remember that we can reaccelerate growth in the 2018 to '21 time period should commodity prices exceed what we're using in our current five-year plan guidance. Looking specifically at the EP program, across all three complexes, we're currently operating 17 drilling rigs and three frac spreads.

We have approximately 175 new wells to tie in during the second half of '17, and as mentioned, we expect to reach that 250,000 BOE per day milestone later on in August. The company completed its 1,000th well on the drilling front last weekend with the Wild River 7-9 horizontal, and we started drilling as a company in February of 2009.

But the reality is, all three core complexes are now completely derisked in the principal development horizons and it allows for continually improving capital efficiencies and improving full cycle returns, and you've seen that materialize over the past 24 months. We will complete the 50 million per day Wild River 14-20 plant expansion in mid-September of 2017 and that will allow us to reach the bcf a day production milestone from the Alberta Deep Basin complex.

As mentioned, the Spirit River 3-10 Sour Gas injection plant was expanded from 30 million to 60 million per day during the second quarter. That plant expansion will be fully commissioned next week, and that increased capacity at 3-10 will allow for processing of the additional oil volumes and gas volumes that we're realizing from the expanding Lower Charlie Lake and Montney Place as well as the increasing volumes from the ongoing Upper Charlie Lake base development.

Included within the map of ongoing development program, we have a number of new play discovery and prospect delineation step-out wells planned during the second half. Included in that are 5-6 horizontal step-outs to the Lambert 16-25 Cardium Gas/Condensate discovery, which has now produced 2.3 bcf of gas and just under 70,000 barrels of condensate in the first 180 days of production.

The first of these wells is just finishing up in the horizontal section and it'll be fracturing in the next couple of weeks and then several follow-ups after that. The first of the Viking horizontals into the Viking A pool of Brazeau, we've done very well on the adjoining pool.

They will be drilled during Q3 and are underway right now. We have a four-well Montney horizontal pad following up the high rate Montney oil discovery announced in May of this month on the Peace River High and we should have those results early in Q4.

So plenty of exciting new results to come throughout the second half from the very large EP program that we're executing. And that's all I was going to say for now, and we'll open it up for any questions that you may have.

If you generate the $200 million of free cash flow in 2018, where do you direct that money? How do you prioritize debt reduction, M&A, implementation of NCIB or possibly dividends?

We haven't formally instituted any kind of dividend programs, so the first response would be that we'll put that money into debt reduction temporarily, and then if we see a sustained gas price in the range that we use in our five-year plan, we'll start to hedge that out and that'll prepare us for the ability to consider a dividend later on in the five-year plan.

Okay. The preliminary 2018 outlook is based on higher than strip pricing as of today.

How should we think about spending levels under a strip pricing scenario?

Well, we've just pulled $270 million out, acknowledging to some extent that commodity prices are weaker in the second half of '18 that -- than we're currently forecasting. We're using a $3.25 NYMEX base price.

We have by the end of '18 close to 0.5 bcf actually realizing NYMEX pricing or derivatives thereof in the multiple hubs that we ship to in United States. And then the current AECO prices, we're using $3.15 per MCF in our '18 forecast and it's less than that right now.

We have a significant volume of gas hedged in the winter, ahead of our forecast AECO price for 2018. But we'll continue to monitor it.

But for now, we'll -- we've got a $200 million free cash flow cushion as we currently roll out '18 in the plan.

Okay. And last one for me, you talked about a focus on return metrics driving the CapEx reduction and accretion of free cash flow.

Internally, what return metrics are you guys looking at or benchmarking yourselves to?

We have a slide on that in our corporate presentation where we show the internal rates of return on all three of our core complexes. And the reason the returns will improve slowly and methodically with the contracted CapEx program is twofold.

One is, we'll have less invested in facilities in '18; and secondly, as we hybrid our inventory, that they'll gravitate to some of the very best locations in the inventory, which will add to that return.

Listen, Mike, I wonder if you could give us -- I know that you're working through a certain forecast in terms of prices, but could you give us your inspirational, if not always accurate, forecast on gas and liquids pricing?

Yes, accurate. Well, obviously, we remain bullish on underlying natural gas supply and demand fundamentals having been the supply in the United States is flat, and it does not appear that there's enough EP activity on the gas side to grow those volumes significantly.

And then on the demand side of the equation, I think the components of the demand increase on the natural gas side are actually ahead of schedule. If you look at LNG shipments on the Gulf Coast, the build-out of the chemical industry expansion, the coal to gas conversions and the exports to Mexico, all are a little bit more than forecast, so these underlying supply and demand fundamentals continue to get kind of clouded, if you like, by short-term weather.

But we think it's quite constructive on the natural gas business, and of course, it is forecast to be the largest single component of the energy usage increase going forward over the next couple of decades. So we think we're pursuing the correct commodity.

It's Fai here from Odlum Brown. I was just wondering in terms of your take on [indiscernible] and whether you see some potential opportunities to add to your own portfolio if they do decide to divest some of those assets in the future?

Well, we're -- across all three core complexes, we have a strategic acquisition plan on what -- if the price was right and we were in acquisition mode, what we would look at acquiring. Bear in mind, we've got 300 to 400 wells in each of those core areas and a significant amount of 3D seismics so that we've got a pretty good subsurface idea where the best rocks are.

Our commentary in '17 has been that we don't plan any large acquisitions this year. We'd like a clean EP year.

We'll drill our approximately 300 wells and generate what we think will be at or near the top of industry performance, like the best metrics across the whole business by focusing just on EP drilling and not pursuing acquisition and issuing any shares. So we think the per share metrics this year are going to be spectacular.

That doesn't mean in '18 and '19, we won't look at, perhaps, some modest acquisitions.

And with the pullback in your growth plans for next year and the additional free cash flow, would that give you additional flexibility to consider?

Yes, it certainly would, yes. Yes, it would.

That's a fair comment.

Okay. And the other question I had was -- I've noticed that the operating cost is actually on -- dollars so this quarter compared to the first quarter.

I'm just wondering, you mentioned talking about looking for additional cost savings, I'm just -- could you provide some color on where do you see some of those savings could come from and how sustainable they would be? And I'm not talking about the additional volume increase and driving down the costs per BOE, but are there other opportunities to drive cost down?

Yes, there are.

I mean, some of the emphasis will be on continuing to drive the unit costs down on that recently acquired shell assets. In that instance, when we acquired that -- for example the Deep Basin piece, there are three substantial gas plants in there and each of them were only half full have, so we've been filling those plants rapidly and that has helped drive the costs down.

Certainly, in the Peace River High area, we've extended the gas plant there, so that's going to allow us to post us a little bit more of our own gas. And on the North Side of that in the Mulligan area, we're going to start fill that back, which will continue to drive costs down on the oil side as well.

So I think we've got a number of facets that we're working on and we'll continue to hammer away at the cost. We didn't move the guidance number down by [indiscernible] to $3.50, so I still think that's a reasonably conservative target that we're working towards.

I'm trying to understand the information and I can see that the -- well, the company need $180 million profit, way much better than the previous quarter and -- which is great, it's excellent. My question is this that I was expecting the market to respond to this news but somehow the market didn't take it.

So the question I have is this, am I missing something from that report and other people see it? That's why -- I mean, today I was expecting to have a huge rise of the share price but unfortunately we are in the mood to down the other way, I've been checking up from the last 15 minutes.

So my...

Well, we -- I agree with your comment that we thought we had a very strong quarter and what we've -- the feedback we've gotten is similar to yours, that people are pleased with kind of all aspects of the quarter. As far as predicting market reaction, that's often controlled by more macro factors and other components to it.

So I've kind of given up trying to predict on a daily basis what the market's going to do. I mean, it's certainly frustrating at times when you deliver very strong results and there's not an immediate reaction, but we think the Q2 results will disperse to investors and we think they'll be happy and whether that translates into a share price increase or not, I cannot predict that unfortunately.

Brian?

I don't really have a lot to add to that. I think we're often puzzled by how the market reacts to our performance as well, but we're very comfortable that the fundamentals of our business are strong and you're not missing anything.

If you look at the first six months, we've never had such good returns on our asset, on all three asset areas there is in the entire life of the company. So we're doing everything we actually can.

Yes, we're all in the same team.

You see, if the next three quarters, let's say, if you do just as good as this one here, you're getting almost very close to $0.5 billion profit. And this is huge, it's good.

I mean, we are not IBM but for the size of this company, it will be great, I mean. And, I'll say, well, maybe there is a potential to have, like, dividends in the future.

So some other companies, they're going the other way around and losing money or breakeven, but we made $108 million, so I thought maybe the market is going to appreciate that very much because -- what do they want in order to -- for the share price to go up. I mean, it's been great.

That's...

Well, we're just trying consistently to deliver these results and sooner or later I think we'll get the traction that we all want.

On the Gundy deferral, have there been any challenges with environmental permits or First Nations' approval that committed -- that contributed to the deferral of Gundy?

No. No, none at all.

That's strictly making the decision that where the gas price, we think it's more prudent to moderate the growth rate in '18 and start that plant up in mid-2019. And there'll be an associated slowdown in the pace of drilling.

We'll run one rig continuously at Gundy from now through till the startup of that plant and that will generate enough gas volume to fill the 250 million a day plant when it starts or when it's ready to start. In the meantime, a good portion of that gas can be processed through third parties.

But we've had no environmental feedback. And one of the aspects of our business is we use essentially all recycled frac water for our fracking.

In BC, it is all recycled frac water across both the Sunrise-Dawson complex and that's how we'll do it up at Gundy, so I think we're kind of way ahead of the game on that front.

Now on -- our base case up in Gundy was that the majority of the production, we realized at Station 2. Now with the North Montney line completed in the mid-2019 time range.

Was that a consideration so that production there could realize AECO as opposed to Station 2, at least a portion of it?

Well, we were always planning to use both the Spectra and the new TransCanada system to transport the Gundy volumes. And so that's always been part of the plan and we've nominated in both systems.

Does that help?

Okay, it does.

Thanks, everyone, for calling in, and we look forward to speaking with you in next quarter.

Thank you.