Baytex Energy Corp (BTE) 2016 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp. second-quarter results conference call. Please be advised this call is being recorded.

I would now like to turn the meeting over to Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Wayne. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our 2016 second-quarter financial and operating results. With me today are Jim Bowser, our Chief Executive Officer; Ed LaFehr, our newly appointed 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. And I refer you to our advisories regarding forward-looking statements, non-GAAP financial measures, and oil and gas information contained in today's press release.

All dollar amounts referenced in our marks are in Canadian dollars unless otherwise specified.

I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone. Our operating results for the second quarter were consistent with our expectations and demonstrate the commitment we have made during this downturn to deploy capital efficiently, maintain strong levels of financial liquidity, and reduce costs in all facets of our business.

First, let me highlight some of the -- go through the key highlights for the second quarter. We generated production of 70,000 BOEs per day and delivered funds from operations of CAD81 million, or CAD0.39 per share. We reduced our net debt by CAD39 million during the quarter as funds from operations exceeded capital expenditures. We realized an operating netback of CAD14.39 per BOE, an increase of 147% from Q1.

We reduced operating expenses by 12% to CAD9.42 per BOE in the first half of 2016, as compared to CAD10.70 per BOE in the first half of 2015. In addition, we maintain strong levels of financial liquidity with a senior secured debt-to-bank EBITDA ratio of 0.86 to 1.

Now moving on to our operating results, our emphasis on deploying capital efficiently was evident during the second quarter, as we continued to defer investments in our heavy oil operations in Canada and reduced the pace of development in the Eagle Ford. As a result, we significantly curtailed our level of capital spending, focusing all development activity in the Eagle Ford, our highest rate of return and highest netback asset.

In the second quarter, our exploration and development expenditures totaled CAD36 million, down from CAD82 million in the first quarter of 2016 and down from CAD141 million in the fourth quarter of 2015. During the second quarter, we participated in the drilling of 11 net wells in the Eagle Ford and commenced production from six net wells. This represents a drop of 40% in wells online during the quarter, compared to Q1 of 2016 where we commenced production from 10 wells.

Of the wells that commenced production during the quarter, all have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,300 BOEs per day. We continue to evaluate the multi-zone development potential of our acreage, which sees us targeting the lower Eagle Ford, the upper Eagle Ford and the Austin Chalk formations.

In addition to a reduced pace of development, in Canada, we had shut in approximately 7,500 BOEs a day of predominantly low- or negative-margin heavy oil during the first quarter of 2016. As crude oil prices recovered from the lows experienced earlier this year, we reinitiated production from the majority of these wells in May and June. By the end of June, approximately 6,500 of the 7,500 BOEs per day had been restarted. We expect to resume production from the remaining 1,000 barrels per day in the second half of 2016.

Now for little more color on our financial liquidity. As you will recall, on March 31 of 2016, we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facility to $575 million, granting our bank syndicate -- banking syndicate first-priority security over our assets and restructuring our financial covenants. The revolving facilities, which currently mature in June of 2019, are not borrowing-base facilities and do not require annual or semiannual reviews. Our senior secured debt-to-bank EBITDA ratio at June 30, 2016 was .9 to 1, versus a maximum permitted ratio of 5 to 1.

And our interest coverage ratio was 4.1 to 1, versus a minimum permitted ratio of 1.25 to 1. So we are well within our financial covenants today.

In addition to amending our credit facilities, we have targeted our capital expenditures to approximate our funds from operations in order to minimize additional bank borrowings. In the second quarter, our funds from operations totaled CAD81 million, as compared to capital expenditures of CAD36 million. And in the first six months of this year, our funds from operations totaled CAD127 million, as compared to capital expenditures of CAD117 million.

So I'm very pleased with how we have achieved this objective of balancing our spending profile with our funds from operations through the first six months of this year in what has certainly been a volatile pricing environment.

And importantly, our net debt -- which includes our bank loan, our long-term notes and working capital deficiency -- has decreased to CAD1.94 billion at June 30, 2016 from CAD2.05 billion at December 31, 2015.

In the third quarter, we expect to further reduce our bank debt through noncore asset sales. In the second quarter, we entered into an agreement to dispose of the operated portion of the Eagle Ford for approximately CAD55 million. These assets currently produce about 1,000 BOEs per day and include reserves of 1.3 million barrels on a proved plus probable basis. And this transaction closed yesterday. In addition, in the third quarter we anticipate disposing of noncore assets in Canada that are currently producing about 1,250 BOEs per day.

And now I'm going to discuss our success in reducing our cost structure while maintaining efficiency in our operations and the safety of our employees.

Costs in the Eagle Ford have continued to decrease, with wells now being drilled, completed and equipped for approximately $5.4 million, as compared to $8.2 million in late 2014. Despite receiving -- achieving cost reductions of approximately 20% in Canada during 2015, the prevailing commodity prices have not yet supported additional drilling on our Canadian assets.

Operating expenses have been reduced by 12% to CAD9.42 per BOE in the first half of 2016, compared to CAD10.70 per BOE in the first half of 2015. These cost reductions reflect lower overall cost structure in Canada, combined with our lower-cost Eagle Ford assets representing a larger percentage of our total production.

Transportation expenses are also down, averaging CAD0.90 per BOE for the first six months of 2016, compared to CAD1.94 per BOE in 2015. General and administrative expenses for the second quarter totaled CAD12.2 million, down from CAD15.6 million in the same period last year. The decrease is attributable to reductions in staffing levels commensurate with our lower activity levels combined with a reduction in discretionary spending and lower supplier costs. And as a continued cost control measure, all of our full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective March 1 of this year. These cost reductions, along with improved pricing, have certainly improved our netbacks during the quarter.

We generated in operating netback of CAD14.39 per BOE, which was up from CAD5.82 per BOE in the first quarter. The Eagle Ford generated an operating netback of CAD17.66 per BOE, while our Canadian operations generated an operating netback of CAD10.44 per BOE.

Now with respect to our hedging activities, for the second half of 2016 we have entered into hedges on approximately 46% of our net WTI exposure, with 15% fixed at CAD63.79 US per barrel and 31% hedged using a three-way option structure. We have also entered into hedges on approximately 35% of our net heavy oil differential exposure and 67% of our natural gas exposure.

In 2017, we have entered into hedges on approximately 31% of our WTI exposure using a three-way option structure. We have also entered into hedges on approximately 23% of our net heavy oil differential exposure and 44% of our net natural gas exposure.

A complete listing of our financial derivative contracts can be found in note 15 to our second-quarter financial statement.

And now I'll discuss our plans for the remainder of 2016 along with our updated guidance. As a result of the continued depressed crude prices, our development activity in the Eagle Ford has been reduced. We currently have plans for 3 drilling rigs on our operated lands, as compared to 6 rigs in Q1 of 2016. Given the reduced pace of development anticipated for the second half of 2016, we are now forecasting our full-year 2016 exploration and development capital expenditures of CAD200 million to CAD225 million, down from the previous expectations of CAD225 million to CAD265 million. In light of the dispositions totaling approximately 2,250 BOEs per day that are expected to close in the third quarter, and our reduced spending profile, we now anticipate full-year 2016 production of 67,000 to 69,000 BOEs per day versus our previous range of 68,000 to 72,000 BOEs per day.

Excluding the impact of disposition activity, the approximate 13% reduction in planned spending impacts our 2016 production forecast by only 1%. And, as we have mentioned in previous quarters, our 2016 program remains flexible and allows for adjustment in spending based on changes in the commodity price environment. With this level of capital investment, based on the forward strip for crude oil prices and natural gas prices, we expect our funds from operations to exceed capital expenditures in 2016.

And finally, I would like to highlight a couple of recent appointments. As mentioned on outset of the call, Ed LaFehr has joined Baytex as President. We're certainly very excited to have Ed here. We will all benefit greatly from his strong operational knowledge and leadership as we manage our business for the future. Ed is sitting here right next to me. Welcome to Baytex.

In addition, we have announced today the appointment of Trudy Curran as a Director of Baytex. Our Board is an indispensable source of guidance and support to me, which contributes significantly to the success of our Company. Trudy has an extensive legal background spanning multiple industries over the past 30 years. She will be a great asset to our Board and our Organization as we move forward.

So in summary, as we entered the year, we laid out certain strategic objectives to help guide us through the commodity price downturn, which included deploying capital efficiently, maintaining strong levels of financial liquidity and continuing to emphasize cost reductions. Our second-quarter results were reflective of these strategic objectives, and we remain well-positioned to benefit from a continued oil price recovery.

Now I will ask the operator to open the call for questions.

(Operator Instructions) David Popwich, CIBC.

Good quarter today, and thank you for taking my question. I guess I just wanted to get some sense of how we should expect spending in the Eagle Ford to pan out over the rest of this year and into 2017. You guys have gone from a 4- to 6-rig program down to a 3-rig program. What would be the cues for taking that rig count higher? What kind of commodity price should we think of as you guys are accelerating spending there?

Dave, you're kind of asking us to guess what prices might be, and that's been pretty tough. We have floated between just over CAD50 to CAD26 in the past six months.

So, we are where we are. I think it's where we need to be if we made the adjustments that are necessary to keep our capital expenditures within our FFO. I would expect us needing to approach the CAD50 before we would step back up our activity there. Where we sat here at CAD42 and change, it's a result of the -- kind of the first-quarter and second-quarter pricing levels, and we expect to remain there through the rest the year. We will see what this looks like budget time.

If you go back to 2014, we put our budget out in December. We adjusted it in 2015 in February. We adjusted it again in August. You came in at the end of 2015, we put out a budget in December. We adjusted it in February, and here we are adjusting it again based on the swings that we've seen in this highly volatile market.

So, I would expect us needing to get near CAD50 to try to step back to a few more rigs with a little bit -- another factor or something to keep activity -- step back activity levels higher.

All right. So is it safe to assume that your new production guidance assumes a flat 3-rig program for the rest of this year?

Yes, it does. Pretty much.

And --

Just so you know, we have rigs coming in and out of our lands. Not as much as it used to back when it was -- we were seeing 12 or 13 of 18 rigs during 2014. But Marathon may be running anywhere from 3 to 5 rigs, and we will see anywhere from 2 to 4 of them. So it's kind of an average, and it does vary during any given quarter. But 3 is what we're projecting for the average for the remainder of the year at this time with no change in commodity prices anticipated.

Just lastly to follow up on this [bends], how many rigs do you figure you need to keep running in the play on a net basis to keep your production flat there? How many wells do you have to drill and bring onstream?

Yes, it depends on what level of production was at. When we hit our peak at Q4 of last year, and you get over 40,000 barrels a day, it takes more -- as we drill less, you have less of the high-decline wells online. I would have to do the math. We will get you towards that here as we get through the budget year, but it's, suffice it to say, probably a few more than what we need today.

I look in terms more of frack crudes. Our drilling efficiency continues to improve. We can do with 4 what we did a year ago with 6 in drilling. So it is certainly a rig more than what we are doing today, and probably two factors probably gets you close. So, maybe 2 rigs. I don't -- we will get that as we look closer to the quarter and see where costs are out.

We are down to eight days per rig -- eight days to complete a well -- the drilling operations on a well per rig. So, that has really helped out. Kind of gives you a bit of a ballpark anyway, Dave.

Sure. That helps. Thanks a lot, guys.

Thomas Matthews, AltaCorp Capital.

Jim, just a quick question on the productivity in the Eagle Ford. This quarter, of the 20 wells you brought on, average 1,300 BOE per day. That follows a similar type result from Q1. Just wondering how sustainable is that? Is that a result of targeting some of your better acreage, or is that due to steps made on well design?

Yes, Thomas, it's a little bit of both. There is no doubt that we are continuing to change the spacing of fracks, the amount of sand, the type of perforations, the targeting of the zones within the multi-stages. That evolution continues, and some of it is because of that. And it's also no doubt that we are drilling with only 3 rigs running our lands. We are drilling the very best of what exists out there, and part of it is that. So we've had a major step up from 2015 to 2016. I think it approaches a couple hundred barrels a day in just these first six-month wells from what we did last year, and it's a little bit of both.

Okay. Great. I know there's always been kind of a little bit of a disconnect between what Marathon lists in their presentation and then what you guys have in yours. And obviously there might be a level of conservatism there. Just wondering when or if you would be ramping those numbers up a little bit.

Yes, probably not yet. And keep in mind that they are drilling outside in the Eagle Ford lands that we do not have interest in, and so their data will be different.

Right, right. Okay. And then just on the Canadian heavy oil, obviously you brought it -- most of it back on in Q2 with prices falling off again. What kind of price on the downside would you need before you would start considering shutting that in and absorbing the costs of the shut-in and then bringing it back on? Is it -- it's kind of likely mid to low 30s again would be required to take that step?

Yes, first of all, I really don't want to think about answering that kind of a question. I hope we -- no, I'm kidding, Thomas. I certainly hope we don't get there. But you are probably -- that's probably close. As we get -- high 30s, I don't think we go through those motions. Low 30s, we start thinking about it.

Okay. Great. And then --

That's a fairly decent estimate.

Okay, sounds good. And then just on the CapEx -- and so you spent essentially CAD26.7 million on E&D spending, and you drilled 11.3 net wells. I would assume those wells weren't completed just given the relationship between the overall costs of the well and how many you drilled.

Yes, we had fewer completions during the quarter. And I outlined the numbers -- it's in our -- the details are in our press release. I think we had about half -- 40% less wells were completed during the second compared to the first.

Okay, okay. Yes, I didn't know where the backlogs stood, I guess, at this point.

Yes. Okay.

Perfect. Thanks, Jim.

Thank you. There are no further questions registered at this time. I would like to return the meeting to Mr. Brian Ector.

All right. Thanks, Wayne. And thanks, everyone, for participating in our second-quarter results conference call today. Have a great day.

Thank you. That concludes today's conference call. Please disconnect your lines at this time, and we thank you for your participation.