Baytex Energy Corp (BTE) 2016 Q4 法說會逐字稿

Good morning ladies and gentlemen. And welcome to the Baytex Energy Corporation. fourth-quarter and year-end results conference call.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to your host Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead.

Thank you Denise. Good morning, ladies and gentlemen. And thank you for joining us today to discuss our fourth quarter and yearend 2016 financial and operating results. With me today are Jim Bowzer our Chief Executive Officer. Ed LaFehr, our President. Rod Gray, our Chief Financial Officer. And Rick Ramsay, our Chief Operating Officer.

While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I refer you to our advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial measures and the notice to US residents contained in today's press release.

On the call today, we will also be discussing the evaluation our reserves at year-end 2016. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And I would now like to turn it call over to Ed.

Thanks Brian. And good morning everyone. I would like to start by expressing my thanks to Jim Bowzer as we transition the CEO role later this spring. Jim has led our organization for the past four and a half years with passion and dedication. And as a result I'm inheriting a highly focused team, poised to build on our three core areas. To take on the challenges and opportunities that lie ahead.

During 2016, I had the opportunity to visit all of our field operations. From Peace River to Lloydminster and down to the Eagle Ford in Texas. I can tell you our teams are very committed and focused on driving value. Over the past two years, the emphasis has been on lowering our cost structure, both in Canada and the US, which we continue to relentlessly pursue. I think it's important to note that as a result of these improved cost efficiencies, our light oil projects in Texas and our heavy oil projects in Canada are competitive with top-tier plays in North America.

I am extremely pleased to be working with a team that delivers what it sets out to accomplish. In that vein, we generated a solid set of results in the fourth quarter and full-year 2016. Production averaged 69,500 barrels of oil equivalent per day in 2016 with capital expenditures of CAD225 million. Both in line with guidance. In addition, we strengthened our financial liquidity, reduced our overall debt, and completed the significant transaction at Peace River that we are very excited about. And I'll update you on this today.

All of this has now given us the strength and momentum to take on two key priorities for Baytex in 2017. The first is to arrest production declines. Through a highly efficient capital development program in both the Eagle Ford and in Canada, which we will substantially progress this year. And secondly, we will also place a high priority on managing our debt position.

Let's first talk about what we're doing now to build operational momentum. We are incredibly excited to start this year with increased activity in the Eagle Ford and in Canada. In the Eagle Ford, we increased our rig activity at the end of 2016 and expect to run four to five rigs and two frac crews throughout 2017. The initial results of our program are very encouraging, driven by larger fracture stimulations in the oil window to the north.

In 2016 we commenced production for 36 net wells and established 30 day initial production rates of 1,300 barrels of oil equivalent per day, which represents a 20% improvement over 2015. In the fourth quarter, Eagle Ford production was stable at 33,500 barrels of oil equivalent per day. Production has increased by approximately 5% in the first two months of 2017 to over 35,000 barrels of oil equivalent per day, as a result of the increased pace of development and improved well performance.

Cost reductions in the Eagle Ford continued through the fourth quarter with wells being drilled, completed and equipped for approximately $4.5 million. Down 20% from $5.6 million in Q1 of 2016. These record low well costs were achieved despite increasing the number of frac stages and profit loading.

In the fourth quarter, we increased the effective number of frac stages per well to 26. And the amount of profit per completed foot to 1850 pound which is an increase of 85%. Two recently compete related pads utilizing higher intensity fracs in the crude oil window of our Longhorn acreage have shown large improvement in production rates compared to wells drilled previously.

Turning to Canada. We are running four rigs today. We have an active first quarter underway, with development drilling at Peace River and Lloydminster combined with increasing production from our recently acquired assets at Peace River. In November, we announced the strategic acquisition of additional heavy oil assets in Peace River. The assets are located immediately adjacent to our existing Peace River assets and more than doubled our land-based in the area.

The acquisition enables further efficiencies and synergies and our operations and significantly enhances our inventory of drilling locations for future growth. We closed the acquisition on January 20 for total consideration of CAD65 million. At the time of closing, the assets were producing 3,000 barrels of oil equivalent per day and had another 3,000 barrels a day shut in.

Since closing the acquisition, we have already increased production by approximately 10% as we initiated phase 1 of our plan to bring on shut in production back online. We have identified approximately 30 wells to be restarted which will contribute to our target exit rate for the acquired assets of 3,500 to 4,000 barrels of oil equivalent per day.

Phase 2 will include additional gas conservation and vapor recovery systems that are expected to be implemented over the next 12 to 24 months. In addition, we are undertaking an extensive review of the operation and expect this will lead to meaningful improvements to our unit operating cost throughout 2017.

We have two rigs currently running at Peace River. The cost to drill complete and equipped with multilateral wells at Peace River is budgeted at CAD2.5 million which is an 11% improvement from the cost of the wells we drilled in Q3 of 2015. The first wells from our 2017 program consisted of 13 laterals and came in approximately 7% below budget. This well was placed on production in early February and established a 30 day average initial production rate of approximately 600 barrels per day which puts this well in the top decile of our historical Peace River results. So needless to say, we are very excited to be drilling again in Peace River.

At Lloydminster we are applying our new multilateral drilling and production techniques adopted from our Peace River region. Which we expect will lead to a 25% improvement in individual well capital efficiencies compared to single lateral horizontal wells.

At [Soto] Lake we have drilled six of eight multilateral horizontal wells planned for the first quarter of 2017. Depending on the overall length and completion, budgeted well costs range from CAD700,000 to CAD900,000. And through efficient operational execution and lower service costs, the cost to drill complete equipped our first six multilateral wells have come in approximately 15% below budget with 30 day initial production rates, either meeting or exceeding expectations. Our most recent two Soto Lake wells are expected to generate 30 day initial production rates of approximately 175 barrels of oil per day. Again, terrific results.

As I said at the outset, building operational momentum is of very high importance for us this year. We are off to a great start with production at the Eagle Ford up 5%. And we are seeing great initial results from our drilling program at Peace River and Lloydminster as I just outlined.

Let's shift to our financial results. In 2016, we targeted our capital expenditures to approximate our funds flow from operations, in order to minimize additional bank borrowings. We exceeded this goal with our funds from operations totaling CAD276 million, generating CAD51 million of excess cash flow. In 2016, we also disposed of certain non-core assets in Canada and in the Eagle Ford for net proceeds of CAD63 million. And we achieved a reduction in cash costs that is operating transportation and G&A expenses of 8% on a BOE basis.

All of this contributed to reducing our long-term debt at the end of the year to CAD1.8 billion, a reduction of 13% year-over-year. Our debt is comprised of a bank loan of CAD191 million, and senior unsecured notes of approximately CAD1.6 billion.

In addition to building operational momentum, we also placed a high priority on managing our debt position. Our bank facility is secure and committed to June of 2019. We are approximately two thirds undrawn on this $575 million facility today.

We are also in a very good position with respect to our debt covenants. Our senior, secured debt to EBITDA ratio is 0.55 versus a maximum permitted ratio of 5.0. And our interest coverage ratio is 3.6 versus a minimum permitted ratio of 1.25. So as you can see, we are in very good shape.

And on our long-term notes, we had no meaningful maturities until 2021. We remain committed to fund capital expenditures from our funds from operation and minimize additional bank borrowings while we look for opportunities to delever the balance sheet.

We continue to manage financial risk through an active hedging program. And for 2017, we have entered into hedges on approximately 51% of our net WTI exposure with 10% fixed at approximately $54.46 per barrel. And 41% hedged utilizing a three-way [collar] structure with downside protection just under $50 per barrel exposing our investors to upside to $59 per barrel. We have also entered into hedges on approximately 33% of our net heavy oil differential exposure and 57% of our net natural gas exposure.

Shifting now to our 2016 reserves. The addition of the Eagle Ford to our portfolio has significantly enhanced the quality of both our production and our reserve space. In 2016, 88% of our capital spending occurred in the Eagle Ford. We did not engage in any reserve generating activity on our heavy oil assets in 2016. In fact during the year as you will recall, we shut in 7500 barrels per day of heavy oil which is now back online. Our reserves report reflects this investment profile showing significant growth in Eagle Ford reserves, offset by a reduction in the reserves associated with our heavy oil assets.

In the Eagle Ford, our proved plus probable reserves increased 6% to 217 million barrels of oil equivalent and we replaced 205% of production. Since the time of acquisition in June of 2014, we have increased our crude plus probable reserves in the Eagle Ford by 30%. In aggregate, our approved plus probable reserves at year-end is 406 million barrels of oil equivalent. Using the December 31, 2016 independent reserves evaluation, the present value of our reserves discounted at 10% before tax, is estimated to be CAD3.9 billion and our net asset value is estimated to be CAD9.05 per share.

So in conclusion, we delivered what we committed to deliver in 2016. In 2017, we anticipate capital expenditures of CAD300 million to CAD350 million. Our production guidance range is 66,000 to 70,000 of oil equivalent per day. And our expected production exit rate reflects an organic growth of approximately 3% to 4% over the 2016 exit production rate.

We are seeing production growth in the Eagle Ford. And we are very pleased with the drilling results to date in Canada. This gives us an excellent start to the year, and builds operational momentum for the future. And with that, I will conclude my formal remarks and ask the operator to please open the call for questions.

(Operator Instructions)

Mike Dunn, GMP FirstEnergy.

Thank you. Good morning folks. A couple of questions if I may.

First, just wondering maybe if you could quantify at all. You mentioned the Eagle Ford, the recent wells with the higher intensity completions having large improvements in rates. Can you put a number on that?

Well we said the rates have been increased from 1,100 barrels of oil equivalent per day to about 1,300 so that is a 20% improvement. In particular, we are moving the program North preferentially to the Longhorn oil window. So, in those cases we abruptly doubled the proppant intensity from -- in fact you would've seen when we were in the Longhorn window a couple of years ago and even last year we were at sand loading of about 800 pounds a foot.

We are now sitting at almost 2,000 pounds a foot and also tightening up the stage spacing from roughly 300 foot stages down to 250, 200 foot stages.

So, it is a matter of being in the oil window and increasing proppant not just overall. The average overall has increased from 1,200 pounds a foot to 2,000 pounds a foot. But we have also been running some stimulations up in the 2,500 pounds a foot range and higher than that. But were getting that 1,300 barrels a day equivalent rate. That is a good solid rate to hang onto.

Okay and secondly just on the technical revisions for the reserves. Maybe just talk to the heavy oil and the tight oil and shale gas revisions. If you could?

Let me start with the heavy oil. Keep in mind that we haven't invested in any sort of drilling and not only that, no strap wells for about 2 years-plus. When there is that lack of investments, and there is no additions clearly. But also it gave us an opportunity to revise some of our mapping.

We have revised our mapping. We looked at performance. And we've got two issues really. The first one is 27 locations have been moved from 2P reserves into, 15 of those were moved to [contingent] and 12 were moved out altogether. So that was in a broad area north of Reno.

There is secondly, a very specific issue that affected about 12 locations. But significantly affected rates in an isolated area of about three and a half sections North of Reno. And that was just simply a reduction of type curves in an area where we had a blocked [band]. But it is a very small number of sections and fairly isolated.

So, this revised mapping I think has improved our view of also acquiring Murphy acreage as well. So we took that into consideration, and have a really good view of the asset at this point in time. On Eagle Ford, that [tank] just keeps getting bigger.

Let me talk about the technical revision. We were very aggressive in developing the upper Eagle Ford this last year. And as we developed the upper Eagle Ford, we made some revisions in the lower Eagle Ford.

But overall we added over 60 million barrels of oil equivalent and we took off [36-ish]. So we are now sitting in a place where we have moved our reserves from 204 million barrels in the Eagle Ford to 216. And over a two-year period we have grown [reserve base] of 30% -- overall great news story in Eagle Ford.

Great. So I understand, the lower Eagle Ford reserves saw negative provisions. Was that because the upper Eagle Ford, I guess spacing-wise you were sharing some of the resource between the wells?

Right we very aggressively developed the Eagle Ford as I said. So there was a small sampling of wells in the lower Eagle Ford in that area we called the stack and frac last year which comes through the middle of the gas condensate window where we reduced reserves on those wells. [Partly, in] far greater numbers increase in the upper. But yes, you're right.

Okay.

Thanks for the question.

Thanks Ed, that's all for me.

Jason Frew, Credit Suisse.

I was just wondered if you could talk a little bit about inflation risk? To what extent you've been able to lock down some services in 2017? And how you're just managing the risk overall of inflation on both sides of the border? Thanks.

Very good question Jason. And were seeing different things on different sides of the border. But the bottom line is were seeing the lowest well cost we have ever seen in the Eagle Ford as well as in our Peace River and Lloyd assets.

So let me talk about Canada first. Very briefly, and then I will go to Eagle Ford. In Canada we locked in unit costs on rigs, bits, cementing, casing.

And as I mentioned in the call we are seeing 15% lower cost both in a Peace River and Lloydminster. And that is lower than what we would have shown the market previously. So we are very excited about that.

We believe that will continue. We project deflation where we're running the business in Canada. Because we don't compete with the high pressure pumping and fracking business in the deep basin. Or down in light oil in southern Saskatchewan.

These are largely open hole multilateral completions. Very simple. And it's all about the drilling. So, our drilling supply chain costs are down a lot. And we're generating 15% reductions below quite a stretchy budget number.

In Eagle Ford, we mentioned we are seeing the lowest well cost ever at CAD4.5 million. So you would've seen the operators talking about sub CAD4 million. And we, in Canada, will add in the equipment tie in.

And that's about CAD500,000 CAD600,000 for us. So we are sitting at [CAD]4.5 million, while the operator talking about [sub] CAD4 million on just on the D&C component.

Now, having said that, for the rest of the year, we've projected some inflation into our budget numbers. On just the pressure pumping business. So we've actually budgeted CAD5 million well costs. As we've shown in some of our IR materials. But were seeing cost today, realized cost of CAD4.5 million.

We have not seen that inflation kicked in yet. We should probably see some in the Eagle Ford only later this year. If that helps Jason.

That is very good color thank you very much.

Thomas Matthews, AltaCorp Capital.

I just had a question on Canadian op costs. I know you shut in a lot of high op cost at Lloydminster production. And then [just] recently brought it back on. And I know there is a bit of an integration period with integrating some of the new Murphy Oil assets.

But I'm just wondering, how much of the increase in op cost carries forward into 2017? Or what kind of normalized Canadian op cost are you guys projecting?

That is a good question Thomas. Our big priority in Canada is to integrate the Peace River acquisition that we just did. So I think as we published in most of the markets, we acquired a CAD30 a barrel asset.

And we run our production operations at an CAD8 a barrel OpEx plus CAD4 transportation so all in, it is CAD30 versus CAD12. We have no intention of continuing a CAD30 a barrel operation.

So we've already taken steps to reduce. That is skewing our numbers to answer your question. But that's what we've projected publicly.

Though our internal plans are to dramatically reduce the dollar per barrel on those acquired [lands]. So, you will see things like us loading up the production through the 433 facility. We have an inventory of 30 to 40 wells that we're basically replacing rod pumps and going in and fixing completions.

And we're already about 20 some wells into that program. So we are loading up the facility there, number one. Number two, is we're [looking at] everything out there a centralized labor model, the infrastructure model, chemicals, polymer flood.

There are lots of things that our Chief Operating Officer and his team are looking at to drive that cost down. So you will see that come down. And you will see us drive the operation model more towards the way we operate.

So I can't give you a number right now, other than what's already in the guidance. Or already out there publicly. But we will beat those numbers.

Great. And then just on the one well. I know on the Peace River the 600 barrel per day well. Was that a result of drilling into some virgin reservoir? Or was that changing [a]completion techniques or the way you're drilling it? Or the number of laterals?

Just if you could shed some light on that one well that would be great.

Is very similar to what we did in the past. It is 13 laterals. It's completed much in the same way.

I would say, we have had two years to rebuild the inventory here. And part of it is the negative on the technical revisions that we had earlier in the call. A lot of it is positive in terms of seeing the best locations even better.

So we've mapped out a program in 2016 that is very attractive. It's going to move around. We're already on our third well. Although we've only brought back in production this one well.

It is 20,000 centipoise it is not the best viscosity we have seen. It is a Darcy permeability rock. It's good rock across that whole 13 laterals.

Our geosteering is probably the best I have seen in my 30 year career in terms of the way Baytex geosteers its wells. So, we have high confidence in the additional locations coming in. But this is a top decile well.

And we are still sticking to our guidance or numbers of 300 to 350 barrels per day. Would be for an IP 30, that would be a standard type curve. But this is a fantastic well and will probably show up on the Alberta best well report sometime so keep your eyes tuned.

Perfect that's it for me thanks.

There are no further questions at this time I will turn the call back over to turn to Mr. Ector.

That's great. Thank you Denise. Thanks everyone for participating in our year-end conference call. Have a great day.

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