Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2017-Q4

[Operator]

Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Tourmaline Oil Corp. Fourth Quarter Results 2017 Conference Call. [Operator Instructions] Scott Kirker, you may begin your conference.

[William Scott Kirker, Secretary & General Counsel]

Thank you, Sylvie, and welcome everyone to our discussion of Tourmaline's 2017 Q4 and year-end results. My name is Scott Kirker, and I'm the Secretary and General Counsel for Tourmaline. Before we get started, I would refer to the advisory on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline Annual Information Form and the MD&A 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, and after his remarks, we will be open for questions.Go ahead, Mike.

[Michael L. Rose, Chairman, President & Chief Executive Officer]

Thanks, Scott, and good morning, everybody. Thanks for dialing in. As I think you've seen Tourmaline had a tremendous 2017 in all regards. Touching on a few of the highlights. We grew our cash flow by 65% to $1.2 billion or $4.47 per diluted share. We delivered full year 2017 earnings of $347 million or $1.29 per diluted share. Underscoring again the inherent profitability of the core EP businesses that we built. The company had record low full year 2017 OpEx of $3.19 per BOE. In '17, we realized 31% production growth over 2016 with a full year average of just over 242,000 BOEs a day, which was within our original full year guidance.Behind that, very strong liquid production growth of 64% in 2017 over 2016. Tourmaline is a top 10 Canadian liquids producer, and I think we'll be the sixth largest non-oil sands liquids producer in 2019 in Canada to go along with being the second largest producer of natural gas.Very strong capital efficiencies in 2017 of $9,500 per flowing BOE. On the reserve front, as previously disclosed, we added 558 million BOEs of 2P reserves, and we grew our liquids reserves by 73%. 2P reserve value was up $2.4 billion in '17, despite lower gas prices used in the engineering price deck, taking our total 2P value to $15.1 billion. And importantly, of the 558 million BOEs added, in 2017, 96% of it came from our internal organic EP program. We had for us record low FD&A costs, $3.76 per BOE, 2P, that includes changes in future development capital. We were $6.79 per BOE for total proved and $8.23 per BOE for PDP reserves. And of note, our PDP, FD&A, including everything, was down 44% from 2016.The 2017 2P recycle ratio was 3.6, which was the best we've done to date in our 9 years of operation. The total crude recycle was 2 and the PDP recycle was 1.7.So after 9 years of operation, we have 2P reserves of 2.2 billion BOEs, including 2P natural gas reserves of 10.7 Tcf and liquid reserves oil condensates and NGLs of about 432 million BOEs. Importantly, we've only booked, by our estimate, 14% of what we believe is a very well-defined future drilling inventory.And of note, Tourmaline's owned and operated infrastructure is the fourth largest gas processing capability in the basin.Looking at financial results in a little bit more detail, cash flow was up 65% or $4.47 per diluted share and that's up from $732 million or $3.12 per diluted share in 2016. So on a per share basis, up 43% year-over-year, and we're very happy with that, as these record cash flows were realized during a year of generally weak natural gas prices. Our gas diversification and hedging strategies have provided a realized natural gas price of $2.89 per Mcf in 2017 and that's a 42% premium over the AECO 5A price of $2.04 in Mcf. So it really underscores what we've done on our long-dated marketing and transportation diversification strategy. We delivered free cash flow in the fourth quarter of 2017 and anticipate that, that will grow and is growing during the first quarter.And as mentioned, our earnings of $347 million really underscore our ability to generate profitable full-cycle growth even in weak commodity price environments. We are proceeding with the implementation of our previously announced dividend program. And that first quarterly dividend of $0.08 per common share will be paid on March 29, 2018, based on shareholders of record on March 14, 2018.A few more comments on our marketing and transportation business. The TransCanada Sundre Crossover project is expected to be completed in April of 2018. And that will allow approximately 380 million per day of gas that's currently flowing to AECO through the NGTL system to be flowing instead southwards through the GTN system to Malin, Oregon. Tourmaline has about 100 million a day of that 380 on a longer-term firm transportation deal. So it's good news for AECO right away, overall, and it's good news for Tourmaline, as we have a significant portion of that redirected flow. So we kind of win twice on that one.A second expansion of the same system is planned in 2019, and that's estimated to redirect an additional 280 million a day of natural gas from AECO, again, into the GTN system, and Tourmaline has a 100 million a day of that 280 as well.And remember, these 2 projects are just a subset of Tourmaline's ongoing multiple initiatives to ensure diversification of our natural gas transportation and marketing business, and it's a strategy that we embarked upon over 5 years ago. We'll have approximately 550 million per day of gas flowing to hubs with NYMEX-based pricing in 2019.Looking at production, as mentioned, the average for 2017 was 242,325 BOEs per day, that was up 31% and on target over our 2016 average of 185,672 BOEs per day.Our 2017 average liquid production of 38,737 barrels per day was up 64% over 2016. Our current production overall is between 270,000 and 275,000 BOEs per day. And our full year '18 average production guidance remains unchanged with a range of 270,000 to 280,000 BOEs per day. And we have approximately 37 wells that we'll bring onstream between all 3 core areas in March and into early April.On the cost management side of the business, our full year 2017 OpEx of $3.19 per BOE was a new corporate record, and we continue to pursue multiple cost-reduction opportunities in all aspects of the business. And these very strong costs include a growing light oil complex and increased liquids production strategy throughout the EP portfolio.We believe that we have the lowest per-stage horizontal drill-and-complete capital costs across all 3 core EP areas. And through a number of internal engineering initiatives, we're targeting a further 5% to 10% capital well cost reduction over the next 2 years.On capital budget, our full year '18 capital budget remains at $1.1 billion. We expect to spend less than $300 million of that during the first quarter of this year. And we'll review the overall 2018 capital program and the allocation between liquids and gas projects during the second quarter and during spring breakup.Our exit 2017 net debt of $1.74 billion was down $35 million from the previous quarter Q3 of '17. And as we previously announced last week, we've already reduced our Q1 '18 debt by a further $72 million. And we are expecting a 2018 exit debt cash flow ratio of about 1.1x.Moving to some specific comments on EP program, just looking at the liquids business, in general. Over the past 2 years, we've increased the focus on liquid opportunities throughout the portfolio, growing our overall liquids production by over 100% in an 18 months' time frame to the current level of 50,000 barrels per day, and that's oil condensate and NGLs. And we have a series of drilling and related facility projects that will grow corporate liquids production a further 50% in the next 18 months to 75,000 barrels per day by the fourth quarter of 2019. So our full year liquids production average for '18 is 50,000 barrels per day. We're currently carrying 60,000 per our forecasted '19. And through a series of projects, we expect we'll have the ability to take that average up as we review the budget during the second quarter of this year.Some specific EP programs we'll start with the Montney turbidite in Sunrise-Dawson in North East, BC. We now have 44 wells drilled and completed into that liquid-rich Montney turbidite horizon. We've a well-defined performance and cost curve for these development wells. The average EUR per well is about 3.1 Bcf of sales gas, 275,000 barrels of condensate and 90,000 barrels of liquids.Average well costs for these approximately 1500-meter laterals it's only CAD 2.86 million, drill, complete and equip. So that yields very strong IRRs of just under 200% and 10-month payout. And that's utilizing the current pricing in our engineering -- independent engineering price deck. That makes these wells probably the most profitable Montney targets in the basin with an NPV of $12 million off that CAD 2.86 million expenditure, and obviously, very low capital efficiencies coming with that.We have about 18 of these turbidite wells shut in, awaiting facility capacity, and that project is underway. The Doe 2-11 project will be completed in Q4 of this year. And that will bring onstream about 3,500 barrels per day of condensate, above and beyond where we are right now. So that's exciting for us.Moving to the Alberta Deep Basin Cardium gas condensate play. We are onto the next pad there, a 2 well pad at Anderson 6-1. That will be drilled during March and then we'll complete that on the other side of breakup in May or early June. Spectacular wells, however. The initial 16-25 discovery well, it has an IP 365 of 10.4 million per day with 306 barrels per day of total liquid. So it's certainly one of the best gas wells in the basin in 2017, but it's probably also one of the strongest liquids production wells as well. Our independent engineers assigned it 15 Bs of gas and 315,000 barrels of condensate and natural gas liquids.The step-out at 7-30 has an IP 60 of 17.5 million a day and even better liquids production, so about 750 barrels per day of total liquids. These wells are averaging between $3.5 million and $4 million to drill and complete. So again, amongst the top decile targets from an economic standpoint in the basin.Moving to the Peace River High Triassic oil complex and latest results from the Lower Montney oil play. We continue to delineate and expand the Lower Montney oil play on the Peace River High in conjunction with our long-dated ongoing Upper and Lower Charlie Lake oil development activities.As previously disclosed, we did acquire 35 sections of primarily undeveloped land right in the heart of the Lower Montney oil play. We did that in Q4 of '17, and we'll be drilling on those lands this year.We also have debottlenecking facility project underway that will bring on about 3,000 barrels per day in -- again, in the fourth quarter of this year, and we announced that last week.Some specific well results. The 1-4 Lower Montney oil well has an IP 90 of 668 barrels per day of oil and just over 5 million a day of natural gas. The 15-16 Lower Montney oil well has an IP 90 of 345 barrels per day of oil, and again, 5 million a day of gas. And the 2-4 well has an IP 60 of 935 barrels per day oil and 5.2 million per day of natural gas.We believe we have the lowest completed well costs in the Lower Montney oil play, and we are averaging sort of between $3.2 million and $3.4 million per 30-plus stage completed horizontal.Currently, we believe we have a Lower Montney oil inventory of about 93 locations, and as our delineation drilling continues in '18, we expect a bias upwards to that inventory. So that's just in the Lower Montney. We've got over 1,600 locations in the Upper and Lower Charlie Lake to complement that. And on the Peace River High. In 2018, we expect to complete and tie-in approximately 75 oil wells during the course of the year, providing a significant boost to the company's overall oil condensate and NGL liquid production total.So that's all I had for highlights at this point. And Brian and I and Scott are more than happy to answer any questions that you might have.

[Operator]

[Operator Instructions] And your first question comes from the line of Bob Fitzmartyn of GMP First Energy.

[Robert John Fitzmartyn, Head of Energy of Institutional Research]

Just remind me what's the time line and cost outlays for the Gundy Creek deep cut plant?

[Michael L. Rose, Chairman, President & Chief Executive Officer]

Sure. The Gundy deep cut is scheduled to come onstream in the second half of 2019. The total capital cost, and that includes installation, is CAD 180 million for a 200 million per day deep cut. The deep cut will not recover ethane. And so we have been paying for certain components of that plant in 2017 that continues in '18, and then the installation happens during the first half of 2019.

[Robert John Fitzmartyn, Head of Energy of Institutional Research]

And how many drills do you expect might -- to fill that plant initially?

[Michael L. Rose, Chairman, President & Chief Executive Officer]

We will, in late '18, early '19, ramp up the drilling out there. We've drilled 3 large pads already. And we have a number of wells shut in because we have limited production capacity out there, which is fine at this point in the gas price cycle. So we'll have more than enough wells to fill that plant in the first half of '19 to start full in the second half of '19. So we probably need 4 pads is the short answer to your question.

[Operator]

[Operator Instructions] There are no further questions at this time. I will turn the call back over to the presenter.

[William Scott Kirker, Secretary & General Counsel]

Thanks, Sylvie, and thanks, everyone, for attending our conference call. We'll talk to you in the next quarter.

[Operator]

This concludes today's conference call. You may now disconnect.