Baytex Energy Corp. (NYSE:BTE)
Q2 2016 Results Earnings Conference Call
July 28, 2016 11:00 AM ET
Brian Aster - SVP, Capital Markets & Public Affairs
Jim Bowzer - Chief Executive Officer
Ed LaFehr - President
Rod Gray - Chief Financial Officer
Rick Ramsay - Chief Operating Officer
David Popowich - CIBC
Thomas Matthews - AltaCorp Capital
Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp's Second Quarter Results Conference Call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Brian Aster, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Aster.
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 Bowzer, 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 meeting of applicable security laws. And I refer you to our advisory regarding forward looking statements, non-GAAP financial measures, and all GAAP information contained in today's press release.
All dollars not 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. 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 cost 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 70000 BOEs per day and delivered funds from operations of $81 million or $0.39 per share. We reduced our net debt by $39 million during the quarter as funds from operations exceeded capital expenditures. We realized an operating net back of $14.39 per BOE an increase of 147% from Q1.
We reduced operating expenses by 12% to $9.42 per BOE in the first half of 2016 as compared to $10.70 per BOE in the first half of 2015. In addition we maintained strong levels of financial liquidity with the senior secured debt to bank EBITDA ratio up 0.86 to 1. Now moving on to our operating results, our emphasis on deploying capital efficiently wad evidenced 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 Eagle Ford.
Our highest rate of return and highest net back asset. In the second quarter our exploration and development expenditures totaled $36 million down from $82 million in the first quarter of 2016 and down from $141 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 2015 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 1300 BOEs per day. We continue to evaluate the multizone development of potential of our acreage which ceases targeting the lower Eagle Ford, the upper Eagle Ford and the Austin Chalk formation.
In addition to a reduced pace of development in Canada we had shut in approximately 7500 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 6500 of the 7500 BOEs per day had been restarted. We expect to resume production from the remaining 1000 barrels per day in the second half of 2016.
Now for a little more color on our financial liquidity. As you will recall on March 31st of 2016 we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million granting our 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 based facilities and do not require annual or semi-annual reviews. Our senior secured debt to bank EBITDA ratio at June 30th, 2016 was 0.9 to 1 versus the 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 expenditure to approximate our funds from operations in order to minimize additional bank borrowing. In the second quarter our funds from operations totaled $81 million as compared to capital expenditures of $36 million and in the first six months of this year our funds from operations totaled $127 million as compared to capital expenditures of $117 million.
So I'm very pleased with how we have achieved this objective of balancing our spending profile with our funds from operations though 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 $1.94 billion at June 30th, 2016 from $2.05 billion at December 31st, 2015.
In the third quarter we expect to further reduce our bank debt through non-core asset sale. In the second quarter we entered into an agreement to dispose of the operated portion of the Eagle Ford for approximately $55 million. These assets currently produce about a 1000 BOEs per day and include reserves of 1.3 million barrels on approved cost probable basis. And this transaction closed yesterday.
In addition in the third quarter we anticipate disposing of non-core assets in Canada that are currently producing about 1250 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. Cost in the Eagle Ford has continued to decrease with wells now being drilled, completed and equipped for approximately US$5.4 million as compared to US$8.2 million in late 2014, despite receiving, achieving cost reductions of approximately 20% in Canada during 2015, the prevailing commodity prices had not yet supported additional drilling on our Canadian asset.
Operating expenses have been reduced by 12% to $9.42 per BOE in the first half of 2016 compared to $10.70 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 $0.90 per BOE through the first six months of 2016 compared to $1.94 per BOE in 2015.
General and administrative expenses for the second quarter totaled $12.2 million down from $15.6 million in the same period last year. The decrease is attributable to reductions in staffing levels commensurate with our lower activity level combined with a reduction in discretionary spending and lower supplier cost. And as a continued cost control measure all of our full time employee salaries and all annual retainers paid to our directors will reduce by 10% effective March 1st of this year.
These cost reductions along with improved pricing have certainly improved our net backs during the quarter. We generated an operating net back of $14.39 per BOE which was up from $5.82 per BOE in the first quarter. The Eagle Ford generated an operating net back of $17.66 per BOE while our Canadian operations generated an operating net back of $10.44 per BOE.
Now with respect to our hedging activities, for the second half of 2016 we've entered into hedges on approximately 46% of our net WTI exposure with 15% fixed at US$63.79 per barrel and 31% hedged using a three way auction 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 auction structure. We've 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 three drilling rigs on our operated lands as compared to six 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 expiration and development capital expenditures up $200 million to $225 million down from the previous expectations of $225 million to $255 million.
In light of the dispositions totaling approximately 2250 BOEs per day that are expected to close in the third quarter and our reduced spending profile, we now anticipate full year 2016 production up 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 adjustments in spending based on changes in a commodity price environment.
With this level of capital investment based on the forward [indiscernible] 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 the outset of the call Ed LaFehr has joined Baytex as President. We're certainly very excited to have Ed here, we will benefit greatly from his strong operational knowledge and leadership as we manage our business for the future and Ed's 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 indispensible 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'll ask the operator to open the call for questions.
Thank you, [Operator Instructions] our first question is from David Popowich from CIBC, please go ahead.
Thanks guys, good quarter today and thank you for taking my question. I guess I just want to get some sense of how we should expect spending on the Eagle Ford to pan out over the rest of this year and into 2017, you guys have gone from a four to six rig program down to a three 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 accelerating spending there.
Dave, you know you're kind of asking to guess what prices might be and that's been pretty tough we floated between just over 50 to 26 bucks in the past six months. So we are where we are, I think it's where we need to be. We made the adjustments that are necessary to keep our capital expenditures within our FFO. I would expect us needing to approach to 50 before we would step back up our activity there. You know where we said here 42 and change, you know 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 of the year and we'll see what this looks like budget time, I mean 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 to the end of '15 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 50 to try to step back to a few more rigs, with a little bit another fractor or something to keep activity, step back activity levels higher.
Alright, then is it safe to assume that your new production guidance assumes a flat three 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 we were seeing 12 or 13 of the 18 rigs during 2014 but Marathon may be running anywhere from 3 to 5 rigs and we’ll see anywhere from 2 to four of them. So it’s kind of an average and it does vary during any given quarter. But three is what we're projecting for the average for the remainder of the year at this time with no change in commodity prices anticipated.
And just you know lastly to follow up on this bent, how many rigs do you figure you need to keep running into play on a net basis to keep your production flat there. How many wells do you have to drill or bring onstream.
It depends to what level production was at, when we hit our peak at Q4 of last year and did over 40000 barrels a day, it takes more you know, if we drill less you have less of the high decline wells online, I’d have to do the math, we'll get you towards that here as we get through the budget year but suffice it to say probably a few more than what we need today. I'll look at in terms more of frac crew, our drilling efficiency continues to improve we can do with four what we did a year ago with six in drilling so it’s certainly a rig more than what we're doing today and probably two fractors probably just to close so maybe two rigs. We'll get that as we look closer to the quarter and see where costs are, you know we're 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 bit of the ball park anyway Dave.
Sure, that helps, thanks a lot guys.
Thank you, the following question is from Thomas Matthews from AltaCorp Capital, please go ahead.
Hey Jim, just a quick question on the productivity in the Eagle Ford, so this quarter of the 20 wells you brought on you know average 1300 BOE per day, that follows a similar type result from Q1. Just wondering, you know 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're continuing to change the spacing of fracs, the amount of sand, the type of perforation, 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 where we are drilling with only three rigs running our land we are drilling the very best of what exists out there and part of it is that, we had a major step up from 2015 to 2016 I think it approaches a couple of hundred barrels a day in just these first six months than 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 you know 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, but probably not yet. And keep in mind that they are drilling outside in the Eagle Ford lands that we do not have interest in 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'd start considering shutting that in and absorbing the cost of this 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, I'm kidding you Thomas, we don't get there but you're 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.
That's a fairly decent estimate.
Okay, sounds good, and then just on the CapEx and so you spent essentially 26.7 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 cost of the well and how many you've drilled.
Yes, we have fewer completions during the quarter and I outlined a number of, the details are in our press release I think we had about half a, 40% less wells were completed during the second compared to the first.
Okay, I didn't know where the backlog stood I guess at this point.
Good, perfect, thanks Jim.
Thank you, there are no further questions registered at this time, I would like to return the meeting to Mr. Brian Aster.
Alright, 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.
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