Tourmaline Oil's (TRMLF) CEO Mike Rose on Q2 2016 Results - Earnings Call Transcript

| About: Tourmaline Oil (TRMLF)

Tourmaline Oil Corp. (OTCPK:TRMLF) Q2 2016 Earnings Conference Call August 4, 2016 9:30 AM ET


Scott Kirker - Secretary and General Counsel

Mike Rose - President and CEO

Brian Robinson - VP of Finance and CFO


David Phung - Credit Suisse


Good morning, my name is Michelle and I will be your conference operator today. At this time, I would like to welcome everyone to the Tourmaline Oil Corp Q2 2016 Results Discussion. [Operator Instructions]

I would now like to turn the call over to Mr. Kirker, General Counsel. Please go ahead.

Scott Kirker

Thank you Michelle and welcome everyone to our discussion of Tourmaline's Q2 2016 results. I'm Scott Kirker. I'm the 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 and on our website. 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 to some of the highlights and after his remarks both Mike and Brian will be available for questions.

Go ahead, Mike.

Mike Rose

Thanks Scott and thanks everybody for dialing in. I will start with a few of the highlights. Our first half 2016 average production of 190,820 Boes per day was within full-year 2016 guidance of 190,000 to 195,000 Boes per day and more importantly up 33% year-over-year. We had record low second quarter OpEx of $3.41 per Boe and that’s down 17% year-over-year and 8% quarter over quarter and that helped drive record low all-in cash cost of $6.58 per Boe. Our Q2 cash flow of $134 million was strong, it’s a result of our continued cost control emphasis but it remained strong even through a period of particularly weak natural gas prices. Q2 capital spending of $49 million was lower than forecast and it led to Q2 exit debt of $1.37 billion which is down $158 million quarter-over-quarter. We expect on the operational front to bring approximately 100 new wells on stream prior to year-end 2016 and that will allow us to meet or exceed our exit target for 2016 of between 210,000 and 215,000 Boes per day. And looking at our BC Montney, we expect that to grow on the production front by over 50% in the next 18 months.

Looking at production, as mentioned first half production was up 33% year-over-year and already within our full-year guidance of 192,000 to 195,000, we expect strong second half of 2016 with those 100 new wells coming on stream across all three core complexes. Second quarter production of 185,812 Boes per day represented 29% increase over the second quarter of 2015 production of 143,000 Boes per day. We did advice in June that second quarter would be reduced by between 9,000 and 9,500 Boes per day due to significant unplanned firm service restrictions on the TransCanada system in May and June and a lengthy production interruption at the third-party deep cut facility we access at Wild River-Saturn in the Deep Basin. Those 5,000 barrels per day of company interest NGL volumes from this facility will be resolved in the next few days. We remain on track for our full-year production guidance between 190,000 and 195,000 Boes per day and full year that will be 25% year-over-year growth. And as mentioned, we continue to target and are on target for the exit volume of 215,000 Boes per day which includes 1.1 Bcf of natural gas production. We continue to time the start-up of our new second half ‘16 production to match an anticipated steadily improving commodity price environment during the fourth quarter and continuing into 2017.

Note that the 2017 production guidance of 215,000 Boes per day is based on a 12-rig drilling program and we’re staffed to efficiently execute a 20 to 22 rig program, so there is plenty of upside. We will expand that drilling program should commodity prices generate incremental cash flow in excess of our current 2017 forecast of 1.2 billion. And the impact of our steadily reducing drill complete capital cost is not factored into the current 2017 guidance which essentially allows for more wells for the same capital budget. Looking at the financial results briefly, our first half EP capital spending was $281.6 million which was below the previously reduced estimate of $310 million and less than first half cash flow of about $294 million. Our second quarter EP spending was $49 million well less than second quarter cash flow of $134.3 million and second quarter cash flow remained strong despite natural gas prices averaging for us of $1.87 per Mcf. Steadily improving natural gas prices and the Company's gas marketing activities are expected to yield potentially stronger than anticipated second half 2016 cash flow.

And of note, approximately 84% of our second half ‘16 gas volumes are either priced at hubs other than the AECO hub or are financially hedged. Our Q2 net debt of $1.37 billion was down from Q1 2016 net debt of $1.5 billion and that's the second consecutive quarter of net debt reduction for the company. We will continue to execute cash flow budgets in ‘16 and ‘17 and as you know we’ve maintained a very strong balance sheet through our entire 7.5 year history. At mid-year 2016, we had approximately $760 million of unused credit capacity on our recently extended bank facility. Looking at capital costs, and operating costs, as mentioned, Q2 OpEx was $3.41 per Boe, a record low for us and that’s down 17% year-over-year. Last year's OpEx for second quarter was $4.10 per Boe for comparison sake and it’s well ahead of our actual - original 2016 OpEx guidance of $4.25 per Boe. And as a result we’ve reduced our full-year OpEx guidance down to $3.75 per Boe.

Drill and complete capital costs were reduced by an average of 30% across all three core complexes between Q1 2015 and Q1 2016. And with the ongoing EP program right now, we are targeting a further 15% reduction in D&C capital costs through the balance of the year. We’ve actually already achieved new pacesetter costs during the past month and all three core complexes, eclipsing the Q1 2016 pace-setter costs that we just delivered. And these continued cash and capital cost reductions served to drive down the threshold gas price that we require for full cycle profitability and related strong earnings.

Looking at the EP program specifically, we’re currently running 10 rigs across the three operated complexes. We’re right now focusing more on drilling the longer lead time, multi-well pads in the third quarter and then there will be a corresponding ramp up of completion activity in the fourth quarter. This ongoing EP program and the existing inventory of already drilled, but uncompleted wells will yield about 100 new producing wells to bring on stream by year-end. We also expect to reach the 30,000 barrel per day of total liquids production either late in ‘16 or early in 2017.

And in that capital program, for the second half, there is no new significant facility projects planned. The next plant is our 60 million per day Doe 2-11 gas plant in BC and that’s scheduled for an April 1 ‘17 startup.

The second half EP program has numerous horizontals into new formations and potential new pools, providing lots of reserve and inventory upside. So we’ll disclose as those results become available. We’ll test the Falher C, the Viking, amongst other horizons in the Alberta deep basin. We’re looking to expand the condensate rich lower Montney turbidite in north-east BC and we’ll also test the lower Charlie Lake and lower Montney formations on a broad basis on the Peace River High.

We’re currently looking at our Montney BC gas condensate complex a little more in detail or currently the fifth largest Montney producer in BC with daily production ranging between 50,000 and 55,000 BOEs per day. Upcoming facility expansions timed with the arrival of incremental new firm service transportation agreements will increase production to between 75,000 and 80,000 BOEs per day by the end of Q1, 2018 and that's about 50% growth in 18 months.

We’ll get to the 65,000 to 75,000 BOE per day level at the end of Q1 ‘17 when the aforementioned Doe 2-11 plant starts up. And then there will be a further production growth step to north of 90,000 BOEs per day in Q4, 2018, and that’s timed to our second Sundown expansion.

Looking at our BC cost structure, Q2 2016 OpEx was 320 per BOE, certainly amongst the lowest in industry. Our drilling and complete capital costs for an average 30 stage Montney horizontal well are now down below 2.9 million and we think those are the lowest and with the second-half program, we’ll continue to seek ways to reduce those costs even further.

So that's all I was going to say from an update standpoint, formally and then we'll open it up now for questions.

Question-and-Answer Session


[Operator Instructions] Your first question comes from David Phung from Credit Suisse. Your line is open.

David Phung

Hi, good morning. Just maybe a few questions on your D&C capital cost reductions, can you elaborate on what you’ve done so far to achieve the 10% reduction from last year, and specifically on the second half of this year’s drilling program, any elaboration of what you are specifically targeting to achieve the 15% reduction in costs and at a higher level, if you’re to characterize what inning you’re in at a ballgame in terms of driving your D&C costs down, are you in the third inning of driving your costs down or are you in the later stages of the game in terms of driving your D&C costs down? Thanks.

Mike Rose

Sure. We did provide in our corporate overview about a month ago, a little bit more granular detail on the upcoming cost reductions. So for the 15% reduction, we’re seeking going forward with a program that started up in July 2016. Where we see those cost reductions and most of them are from an operational efficiency standpoint and not topline service cost reductions. So the areas where we drop it, it comes from the multi-well pad drilling where you reduce rig moves and lease cleanup costs. We've systematically reduced rental costs for all the ancillary services that are associated with drilling a well. We are continually optimizing our well-design and that includes changing fluid use and rotary steering capabilities.

We've reduced our downhole assembly costs and we continue to expand our water management optimization on the fracking side and that’s basically by providing your own frac source water and recycling it. So, so far, and we've got about a dozen wells that we’re through so far with second half program. We’re seeing those 15% reductions and it will be across all three core complexes to put it in baseball perspective. I think we’re in the middle of the game as far as cost reductions come, the biggest wins will occur in the deep basin because that's where we’re continually expanding the size of the multi-well pads that we're drilling and see from an efficiency operating standpoint, the most opportunity to reduce capital costs on the drilling side. Does that help, David?

David Phung

Absolutely, thanks. Maybe just one follow-up question on operations, have you been impacted at all from weather this past few weeks or months?

Mike Rose

A little bit, but I mean, I don't see that right now as a huge problem, other than it keeps your inning [ph] note baseball games, but I hate blaming the weather.

David Phung

All right, thanks guys.


[Operator Instructions] I have no further questions at this time. I turn the call back over to Mr. Scott Kirker for closing remarks.

Scott Kirker

Thanks, Michelle, and thanks everybody for tuning into our Q2 report. We will see you next quarter. Thanks.


Thank you, everyone. This concludes today's conference call. You may now disconnect.

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