Baytex Energy Corp. (BTE) Q4 2016 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen and welcome to the Baytex Energy Corp’s Fourth Quarter and Year End Results Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instruction will follow at that time. [Operator Instructions] as a reminder this conference is being recorded. I would like to turn the conference over to your host Mr. Brian Aster, 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 year end 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 security laws. I refer you to our advisory’s 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 of 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 the call over to Jim.

Thanks, Brian and good morning everyone. I’d like to start by expressing my thanks to Jim Bowzer, that we transitioned the CEO role later this spring. Jim has lead our organization for the past 4.5 years with passion and dedication and as a result I’m inheriting a highly focused team poised to build on our three quarter areas and take on the challenges and opportunities that lie ahead. Through 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 is 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 project in Canada are competitive with top tier plays in North America. I’m 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 average 69,500 barrels of oil equivalent per day in 2016 with capital expenditures of $225 million both in line with guidance. In addition, we strengthened our financial liquidity, reduced our overall debt and completed a significant transaction in Peace River that we’re 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 [ph] 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’re 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 large fracture stimulations in the oil window to the north. In 2016, we commence production from 36 net wells and establish 30-day initial production rates of 1,300 barrels of oil equivalent per day which represents 20% improvement over 2015. In the fourth quarter Eagle Ford production was stable at 33,500 barrels of oil equivalent per day. Production is 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 US$4.5 million down 20% from US$5.6 million in Q1, 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 proppant per completed foot to 1,850 pounds which an increase of 85%. Two recently completed pads utilizing higher intensity fracs in the crude oil window of our Longhorn acreage has shown large improvement in production rates compared to wells drilled previously. Turning to Canada, we’re 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 base in the area. The acquisition enables further efficiencies and synergies in our operations and significantly enhances our inventory of drilling locations for future growth. We close the acquisition on January 20 for total consideration of $65 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 one 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 two will include additional gas conservation and vapor recovery systems. They’re expected to be implemented over the next 12 to 24 months. In addition, we’re undertaking an extensive review of the operation and expect us will lead to meaningful improvements to our unit operating cost throughout 2017. We have two rigs currently running at Peace River, the cost of drill complete and equip a multi-lateral well at Peace River is budgeted at $2.5 million which is an 11% improvement from the cost of the wells we drilled in Q3, 2015. The first wells from our 2017 program consisted 13 laterals and gained approximately 7% below budget. This well was placed on production in early February and established 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’re very excited to be drilling again in Peace River. At Lloydminster, we’re applying our new multi-lateral 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 Soda Lake, we have drilled six of eight multi-lateral horizontal wells planned for the first quarter of 2017. Depending on the overall length and completion, budgeted well cost range from $700,000 to $900,000 and through efficient operational execution and lower service costs, the cost to drill, complete, equip our first six multi-lateral wells have come in approximately 15% below budget with 30-day initial production rates either meeting or exceeding expectations. Our most recent two Soda 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 a very high importance for us this year. We are off to a great start with production at the Eagle Ford up 5% and we’re 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 $276 million generating $51 million of excess cash flow. In 2016, we also disposed certain non-core assets in Canada and in Eagle Ford for net proceeds of $63 million and we achieved reduction in cash cost that is operating, transportation and G&A expenses up 8% on a BOE basis. All of this contributed to reducing our long-term debt at the end of the year to $1.8 billion. A reduction of 13% year-over-year. Our debt is comprised of a bank loan of $191 million and senior unsecured notes of approximately $1.6 billion. In addition to building operational momentum, we also placed a high priority on managing our debt position. Our bank facility is secured and committed to June 2019, we’re approximately two-thirds undrawn on this US$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’re in very good shape. And on our long-term notes, we have 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 continued 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 US$54.46 per barrel and 41% hedged utilizing a three-way collar structure with downside protection just under $50 a barrel, exposing our investors to upside to $59 a barrel. We’ve also entered into hedges are 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 through our portfolio has significantly enhanced the quality of both our production and our reserves base. In 2016, 88% of our capital spending occurred in the Eagle Ford. We did not engage in any reserves generating activity on our heavy oil assets in 2016. In fact during the year as you’ll recall we shut-in 7,500 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, 2014 we’ve increased our proved plus probable reserves in the Eagle Ford by 30%. In aggregate, our proved plus probable reserves at year end is 406 million barrels of oil equivalent. Using the December r31, 2016 independent reserves evaluation the present value of our reserves discounted at 10% before tax is estimated to be $3.9 billion. And our net asset value is estimated to be $9.05 per share. So in conclusion, we delivered what we committed to deliver in 2016. In 2017, we anticipate capital expenditures of $300 million to $350 million. Our production guidance range is 66,000 to 70,000 barrels of oil equivalent per day and our production exit rate reflects an organic growth of approximately 3% to 4% over the 2016 exit production rate. We’re seeing production growth in the Eagle Ford and we’re 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’ll conclude my formal remarks and ask the operator to please open the call for questions.

[Operator Instructions] and your first question comes from Mike Dunn with GMP Firstenergy. Your line is open.

Thanks. Good morning folks. A couple of questions if I may. First, just wondering maybe if you can quantify it 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 to oil equivalent per day to about 1,300 so that’s a 20% improvement. But in particular we’re moving the program north preferentially to the Longhorn oil window, so in those cases we’ve roughly doubled the proppant intensity from back you would have seen, when we were in the Longhorn window, a couple of years ago and even last year we were to sand loading about 800 pounds a foot. We’re now sitting at almost 2,000 pounds a foot and also tightening up the stage facing from roughly 300-foot stages down to gallons of 250, 200. So it’s a matter of being in the oil window and increasing proppant and not just overall. The average overall is increased from 1,200 pounds a foot to 2,000 pounds a foot but we’ve also been running some stimulations up in the 2,500 pounds a foot range and higher than that. But we’re getting that 1,300 barrels a day equivalent rate, that’s 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, I guess the tight [ph] oil and shale gas revisions, if you could?

Yes. Let me start with the heavy oil, keep in mind we haven’t invested in any sort of drilling and not only that no strapped wells for about two plus years. So when there is that live investment and there is no additions clearly, but also it gave us an opportunity to revise some of our mapping and we have revised our mapping, we looked at performance and we 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 sort of broad area north of Reno. There is secondly a very specific issue that effected about 12 locations, but significantly affected rates in an isolated area of about 3.5 sections north of Reno and that was just simply a reduction of type curves in an area where we had a blocked [indiscernible], but it’s 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. We - let me talk about technical revision, we were very aggressive in developing 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 had it over 60 million barrels of oil equivalent and we took off 36-ish, so we are now sitting in a place where we moved our reserves from 204 million barrels in the Eagle Ford to 2016 over two-year period we’ve grown the reserve base 30%. So overall great new story in Eagle Ford.

Great and maybe, if I can just, so I understand, the lower Eagle Ford reserves saw negative revisions, was that because the upper Eagle Ford because of I guess spacing wise you were sharing some of the resource between the wells?

Right, we very aggressively developed the upper Eagle Ford as I said and so there was a small sampling of wells in the lower Eagle Ford in that area, we call the stack and frac last year, which comes through the middle of the gas condensate window, where we reduced reserves on those wells, but we’re getting far greater numbers increased the upper. But yes, you’re right.

Okay.

Thanks for the questions.

Thanks Ed, that’s all for me.

Your next question comes from Jason Frew with Credit Suisse. Your line is open.

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.

Yes, very good question Jason and we’re seeing different things on different sides of the border. But the bottom line is, we’re seeing the lowest well cost we’ve ever seen in the Eagle Ford as well as in our Peace River and Lloyd assets. So let me talk about Canada for just very briefly and then I’ll go with the Eagle Ford, but in Canada we locked in unit cost on rigs, bit cementing, casing and we’re - as I mentioned in the call. We’re seeing 15% lower cost both in the Peace River and in Lloydminster and that’s lower than what we would have shown the market previously. So we’re 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, the fracing business in the Deep Basin or down in the light oil in Southern Saskatchewan. So these are largely open hole multi-lateral 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’re seeing the lowest well cost ever at $4.5 million. So you would have seen the operators talking about sub $4 million and we, in Canada will add in the equipment tie-in and we - that’s about $500,000, $600,000 for us. So we’re sitting at $4.5 million, while the operator is saying sub $4 million on just the D&C component. Now having said that, for the rest of the year we projected some inflation into our budget numbers on just the pressure pumping business, so we’ve actually budgeted $5 million well cost as we’ve shown in some of our IR materials, but we’re seeing cost today realized cost of $4.5 million, we haven’t seen that inflation kick in yet. But we should see it; we should probably see some in the Eagle Ford only later this year. If that helps, Jason.

Yes, that’s very good color. Thank you very much.

Your next question comes from Thomas Matthews with AltaCorp. Your line is open.

I just had a question on Canadian op costs. So I know you shut-in a lot of high op cost at Lloydminster production and then [indiscernible] 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?

It’s good question, Thomas. Our big priority in Canada is to integrate the Peace River acquisition that we just did. So I think as we’ve published in most of the markets, we acquired $30 barrel asset and we run our, production operations at $8 barrel OpEx plus $4 transportation, so all in its $30 versus $12. We have no intention of continuing a $30 barrel operation, so we’ve already taken steps to reduce without skewing our numbers to answer your question. But that’s what we projected publicly though our internal plans are to dramatically reduce the dollar per barrel on those acquired lands. So you’ll see things like us loading up the production through the 433 facility, we’ve already 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’re loading up facility there number one. Number two, is we’re looking at everything out there, the centralized labor model, the infrastructure model, chemicals, the 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’ll see that come down and you’ll see us drive the operation model more towards the way we operate. So I can’t give your number right now other than what’s already in the guidance or it’s already out there publicly, but we’ll meet those numbers.

Okay, 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 incompletion 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.

Well it’s very similar to what we’ve done in the past. It’s 13 laterals, it’s completed much in the same way, but I would say we’ve had two years to rebuild the inventory here and as [indiscernible] part of it’s the negative on the technical revisions that we had earlier in the call. But a lot of it is positive in terms of seeing the best locations even better, so we’ve mapped out a program 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’s 20,000 centipoise, so it’s not the best viscosity we’ve seen, it is a Darcy permeability rock. It’s good rock across that whole 13 laterals. Our geosteering is probably the best I’ve seen in my 30-year career in terms of the way, Baytex geosteer’s it’s wells. We have high confidence the additional locations coming in, but this is a top decile well and we’re still sticking to our guidance sort of numbers of 300 and 350 barrels a day would be for an IP30 that would be a standard type curve. But this is a fantastic well and it’ll probably show off on the Alberta [indiscernible] report sometime, so keep your eyes tuned.

Perfect that’s it for me thanks.

Okay, there are no further questions at this time. I’d turn the call back over to Mr. Aster.

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