Tourmaline Oil Corp.

Scott Kirker - Secretary and General Counsel Mike Rose - President and CEO Brian Robinson - VP of Finance and CFO

Fai Lee - Odlum Brown

Thank you, Mike and welcome everyone to our discussion of Tourmaline's Q3 results. My name is Scott Kirker and I am Secretary and General Counsel of 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, our President and Chief Executive Officer; and Brian Robinson, our Vice President of Finance and Chief Financial Officer. Mike Rose will start by speaking to some of the highlights of the quarter and after his remarks both Mike and Brian will be available for questions.

Go ahead, Mike.

Thanks, Scott. Morning, everybody.

Thanks for dialing in and we're pleased to review our Q3 financial and operating results. Starting with the highlights, we had Q3 earnings of just under $25 million and further underscores the profitability of all three of our core resource plays that we're actively developing.

Third quarter 2016 cash flow was $185.5 million and that was up 38% from the second quarter, the previous quarter. We were happy that we set our all-time record low OpEx cost, it came in at 326 Boe for Q3 and that's a continuation of our quarterly trend of operating cost reduction and it's a 25% reduction year-over-year.

We had realized natural gas prices of 280 per Mcf in the quarter and that's $0.42 per Mcf higher than the average AECO price of 238 for the quarter and it demonstrates the company's long-term emphasis on selling natural gas into multiple strong markets throughout North America, coupled with our prudent financial hedging practices. We have maintained our balance sheet strength with net debt for the quarter coming in at $1.39 billion and that's driven primarily by a continued emphasis on managing our E&P capital spending within cash flow and we did that in Q3 and in the previous quarter as well.

We are very excited about the Shell transaction, the financing associated with that closed last week and so we won't go over that again at this point. But it is set to close on November 30th.

And our Board of Directors has approved $1.35 billion 2017 EP capital program - pro forma to Shell acquisition. Moving to the financial results and the upcoming capital program.

As mentioned third quarter '16 cash flow of $185.5 million was up 38% from the previous quarter and that's a result of better cost performance than forecast, better than anticipated realized commodity pricing. S mentioned we had our record low Op cost at 326 per BOE with the earnings of $25 million it demonstrates we're profitable on a full cycle basis in these relatively low natural gas price environments and that's demonstrated and underscored by our emphasis and progress on both capital and cash cost control.

And we continue to drop the natural gas price required for the company to be profitable on a full cycle basis. We did achieve the 15% second half 2016 drilling complete, capital cost reduction targets and we did that in all three core operated areas and what that will do for us is, it will allow us to drill an incremental 20 wells within the same capital budget for 2017.

As it stands now, we plan to operate a 17 rig program in 2017. That would be pro forma to Shell acquisition and that's up from 12 rigs previously and we can still do that within a cash flow budget for the year, with the pricing assumptions that we're using.

Third quarter EP capital spending was $180.6 million and that compares to cash flow of $185.5 million. We did complete two modest acquisitions in the third quarter of '16, one at Obed in the Deep Basin and one at Dawson-Doe in Northeast BC.

The total purchase price for both assets was $37.6 million. The Obed property is actually joined with Shell, and internally will subsequently acquire the balance of the property when we close the Shell transaction at the end of this month.

As mentioned, the Board of Directors approved our 2017 EP capital budget of $1.35 billion that includes the drilling of 300 gross wells. We'll complete the gas plant that we've already started in BC at Doe 2-11 [ph].

We'll complete the expansion of our Spirit River sour gas injection plant at 3-10. It will go from $30 million to 60 million.

We have a compressor expansion plan at our very large Wild River 14-20 gas plant site and that's just compression in the lad 3 million a day of capacity and we will build the Sundown pipeline lateral in Northeast BC. Approximately 45 of the 300 plan wells in '17 will be on the acquired Shell assets.

We do continue to maintain a very strong balance sheet with low debt to capital ratios. We are expecting debt to cash flow of approximately one time in 2017 pro forma the Shell transaction and the associated total EP capital program of $1.35 billion.

2017 capital program is less than our anticipated '17 cash flow of $1.44 billion. On the production side, we're targeting to achieve our 2016 exit target of 210,000 BOE a day at the end of November, we are expecting now for 2017 base production of 225,000 BOEs per day and that's up from 215 previously, but that doesn't include the Shell transaction.

Pro forma to Shell transaction we're expecting average production between 250,000 and 260,000 BOEs per day in '17 and that represent year-over-year growth of over 30% in 2018 in our guidance is out on '18 as well. On a preliminary basis we're expecting a further 20% to 25% production growth associated with the program that year.

Q3, 2016 production was lower than Q2 due to a number of transportation, third-party and weather issues. We are still on track however, to achieve our full-year average production between hundred 190 and hundred and 195,000 BOEs per day and that will yield ultimately 25% year-over-year growth 2016 versus 2015.

And that will happen as we have over hundred new wells coming on stream in the second half. Almost all of them coming on stream now in the fourth quarter, we've brought over 30,000 BOEs a day of new production on stream thus far in Q4, and we're on one of the largest production ramps in our corporate history with record wells at record low cost and in all three core complexes.

So that takes us to the EP update and we'll hit a few highlights there, currently we're running for 14 drilling rigs and the distribution right now is nine in the Alberta Deep Basin, 2 in our Northeast BC Montney gas condensate complex and 3 on our Peace River high Charlie Lake oil complex. As mentioned, we'll bring approximately hundred wells on stream between September and December, 42 of those have been started up since mid-September.

Some of the individual well highlights on our Peace River high Charlie Lake oil complex 4-13 [ph] upper Charlie Lake well right at the north end of the complex, has averaged 658 barrels per day of 31 EPI oil, and about 0.7 million per day of natural gas over the first 42 days of production, so on a BOE basis that’s 768. Our upper Charlie Lake well at the north end of the Spirit River complex its averaged 865 barrels per day of oil production and 1.8 million per day of gas over the first 22 days of productions, so a lot of these wells are just come on stream, but they are very strong.

The first of our lower Charlie Lake step outs to December 15 discoveries, so far its averaged 1379 barrel per day of oil 35 API and just over 2 million a day of gas for a combined BOE rate of 1,730 and that's a 30 day IP now. Cumulative oil production alone is over 50,000 barrels from that not well.

We have five additional lower Charlie Lake horizontals that will come on stream during this quarter as we continue to delineate what we now believe is a significant new pool that complements the very large upper Charlie Lake complex. Looking at the cost front, there's been great progress really in all three core areas with the second half EP program for the Northeast BC Montney we're now drilling those completed horizontals for $2.75 million, that's an average over the last 12 wells.

So I think some meaningful stats and those are average 30 stage completions. Our average drilling complete cost for our Peace River high Charlie Lake complex horizontals are now down to $2.4 million.

Again, that's an average over the last 12 wells and that's below our target of $2.7 million and those are 27 stage completions on average And our average D&C cost for our Alberta Deep Basin Cretaceous horizontals are $3.67 million over the last 20 wells and that's compared to a target of $4.4 million and those completions average between 22 and 24 stages, depending how long the horizontals are. Our liquids rich lower Montney Turbidite development in Northeast BC continues to deliver very high condensate production rates.

The most recent horizontal testing at just under 700 barrels per day of condition with 3.2 million in a day of associated natural gas. And we've got a whole new slate of deep basin horizontal wells that will dominate the Alberta Gas well rankings.

We highlighted one of these new 35 plus million a day well, it was a well rich horizontal in the press release. So that's all I was going to say for the formal dissertations.

So we'll open it up for questions at this point.

Thank you. Mike, I know that your transportation cost have creeped up a bit this quarter-over-quarter, and it looks you are transferring gas to Malin, Oregon, are you be able to quantify the increase in the net back from - I guess associated with a higher transportation cost?

Yes. Hi, Fai.

It’s Brian, the CFO. As far as the quarter goes, that that was the biggest single driver was the extra total we paid to get the gas through the Malin and that total when compared to the gas price itself gives us a net back of C$0.70 higher than what we would achieved had we sold that gas at AECO.

So that’s the net effect of the two items.

Okay. And at $0.70 per BOE?

That’s $0.07 per Mcf, yes.

Oh, per Mcf.

And there were couple other adjustments in the quarter there on the transportation side that drove it off a bit, I expect it will gravitate debt back down.

Some of it was weather-related trucking on the oil side.

Okay. And the in turn to this opportunity to increasing that back from moving to Oregon is that - do you see that as more of a one-time opportunity, or do you see this something that you can capitalize on going forward?

I think it will continue on as we grow our volumes, there we're currently doing 105 million and in the quarter all that gas was sold at Malin, starting late in October we're removing about three quarters of that down into San Francisco city gate and achieving yet a higher net back for the company. And we are going to increase the next June to 165 million about three quarters of which goes to San Francisco and then in 2018, mid-18 we're going to move that up to 200 million a day with the same split between Malin and San Francisco.

Okay, great. And I know it’s in the presentation that - just to turning to Shell, your activation that you are talking about driving down the operating cost from 550 per BOE to 350 and what exactly are you going to be doing that's different than what Shell is being doing in terms that’s going to allow you to capitalize the cost savings?

Well, the principal main driver on that and that’s a deep basin slide I think you're looking at is there is between 100 and 125 million a day of room in the three plants that we'll acquire. And so the easiest way to drive the Op cost down is to fill those plans up in 2017 and that is the current development plan for the Shell Deep Basin assets.

So if you double production, you will certainly drive down those per BOE Op cost.

Okay, great. And it’s the last question, I noticed on your guidance for 2017, 2018 that the Shell acquisition looks to be immediately accretive on a cash flow basis.

But I guess free cash flow is a little bit lower, I am assuming there is an interest part to expand, when exactly should we expect that free cash flow I guess to be accretive or would be after…

Well, on a per share basis it's about 10% accretive in 2018, it’s not accretive on the cash flow per share basis, on a net cash flow basis it is, but because of the equity issue we did associated with the transaction. So very strong production growth in '17 and '18, pro forma of the acquisition, strong top line cash flow growth and then it really accretes on a per share basis in 2018.

2009 will be free cash flow five were off our 306-80 gas price which run flat through the period, in 2019 those new asset were cash flow 411 million against CapEx of 179. We do have more intensive capital expenditures in 2018, primarily because we're going to build a gas plant in Northeast BC.

Okay. That’s what I was wondering about.

Thank you.

You bet.

All right. It’s Scott in.

Thanks everyone for dialing in. We'll talk to you next quarter.