Peyto Exploration & Development Corp (OTCPK:PEYUF) Q4 2016 Earnings Conference Call March 2, 2017 11:00 AM ET
Darren Gee – President and Chief Executive Officer
Todd Burdick - Vice President-Production
Kathy Turgeon – Chief Financial Officer
Scott Robinson – Chief Operating Officer
JP Lachance – Vice President-Engineering
Dave Thomas – Vice President-Exploration
Tim Louie – Vice President-Land
Lee Curran – Vice President-Drilling and Completions
Good day, ladies and gentlemen. Welcome to the Peyto Exploration & Development Corp. 2016 Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a Q&A Session and instructions will follow at that time. [Operator Instructions] At a reminder, this conference call is being recorded.
I would now like to introduce your host Mr. Darren Gee, President and Chief Executive Officer. Sir, you may begin.
Well, thanks, Brian, and good morning, ladies and gentlemen. Welcome to Peyto’s fourth quarter and full-year 2016 results conference call. Before we get started today, I do want to remind everybody that all the statements made by the company during this call today are subject to the same forward-looking disclaimer and advisory that we have set out in the fourth quarter news release that was issued yesterday.
In the room with me today we’ve got all the Peyto management team. We’ve got Scott Robinson, our Chief Operating Officer; Kathy Turgeon, our CFO; Dave Thomas, VP of Exploration; JP Lachance, our VP, Exploitation; we’ve got Tim Louie, our VP of Land here; Lee Curran, VP of Drilling and Completions; and Todd Burdick, our VP of Production. So we’ve got the whole gang assembled here to talk a little bit about our year-end.
But before I get started with some general comments about the quarter and the annual results, I do want to again recognize the entire Peyto team for their efforts this year and for this fourth quarter, including all of our field personnel.
We saw some tremendous volatility in natural gas prices in 2016 and of course that required our entire team to remain very nimble in our decision making and with our operations in the field. At Peyto, our job is to maximize profit, not just production; sometimes those two things actually don’t go together. So that means we have to be very cognizant of both prices and costs and react accordingly, which I think we did very successfully in 2016 to make sure we weren’t just incurring losses just to keep the production flowing. So on behalf of all the Peyto shareholders, I just want to throw the big thank you to the entire Peyto team for that effort.
So on to our fourth quarter and year-end results. As mentioned in the press release, we were very active in the fourth quarter with nine drilling rigs. Those were split about one-third in Brazeau and two-thirds in the Greater Sundance area. All of the rigs were drilling Spirit River prospects. During the fourth quarter, we drilled 32 wells in total: 13 Notikewin, 10 Falher and 9 Wilrich. Production for the quarter was growing, but did fall short at the end of the quarter by our expectation by about 5%. There are a few reasons for that.
We had a couple of well results in Brazeau and our Notikewin play that weren’t as big as we expected them to be. And that was mostly because I think we were hunting around for the channel as we drilled horizontally. And I also think we’ve learned a little and we need to have some more geologic control in this play before going forward. And I want to ask JP a question, maybe he can elaborate a little bit on that little later.
We also experienced some high line pressures on TransCanada that impacted our plant capacities. I want to dig a little deeper into that issue with Todd Burdick, our VP of Production. And because of the rapid increase in rig count in the fourth quarter, Canadian rig count jumped from about 120 rigs in the third quarter to 180, average in the fourth quarter. We started to see a bit delay in getting some of our services. So there were a few completions that got pushed into January. We were hoping to get those done by the end of the year and on-stream, but that didn’t happen.
So again that contributed to a bit of the shortfall. But definitely made sense to push them into January rather than pay a bunch more to get those services just to try and hit a production target for the end of the year.
So all of that meant, we exit the year at 105, not the 110 we were thinking that we got to, but really the effect on the returns on the capital that we were investing ultimately isn’t very significant. So that’s really what we’re focused on is maximizing that profit and that return number.
On the financial side for the quarter, came in pretty much as expected. We maintained very strong operating margins of 76%, which was also the average operating margin for the year. We generated about $145 million in funds from operations, spent $129 million in capital and threw off about $38 million in earnings in the quarter. Notably, royalties were a bit up in the quarter on stronger liquids prices, but otherwise our cash costs were still at the very bottom of the industry.
So that’s just a quick summary on the quarter. On the year-end total really was quite a volatile year from a commodity price perspective. We had to hold some of our production offline during the periods when gas price was really low, dipped a couple of times less than $0.50 Mcf. We still had about 25% or so of our gas on the spot market during the year. And so when gas dropped below our replacement costs, we were in about to just throw it away like many of our competitors did, so we shut it in that was the smarter thing to do.
At the same time, I think we had some very attractive service costs, so we tried to do as much as we could to take full advantage of that, keep on drilling and keep on building. But as a result of both of those decisions, I think we ended up with a much better netback, cash netback than many of our peers in the industry. And we added new producing reserves and production at very attractive costs, PDP FD&A at $1.44. I think we have to go back all the way to 2003 to find a year when we did it for less. And so that netback and those F&D costs drove a recycle ratio of about 1.8 times, which is very similar to what we’ve had over the last couple years.
Then our capital efficiency or the cost to add new production at just 10,800 of flowing, which is the lowest we’ve ever achieved. So that was very nice to see, especially in a year when the commodity prices were so volatile.
On the financial side, for the year, total cash costs were $0.76 an Mcfe were the lowest we’ve ever got into. Which was a huge accomplishment for the team and then with some prudent hedging we realized a price of around $3.18 an Mcfe, so that drove pretty nice cash netbacks of about $2.42, $14.50 boe. So still some solid netbacks throughout the year.
In total, we generated $515 million of our operations, funds from operations and $112 million of earnings on this capital program of $469 million. So all in all I think a pretty successful year, all things considered. I do want to take a few moments though at the start of the call here and since we have the entire Peyto management team in the room, I wanted to provide a little bit of additional color on a couple of those items. So maybe I can start off by hitting up Todd Burdick, our VP of Production.
Todd, this sales line pressure issue, we’ve seen some pretty big swings in the TCPL inter-Alberta or Nova Gas Transmission System in terms of air pressures. Can you talk a little bit about what the range of line pressures we’ve seen and the impact to our client capacity and then what have we done to try and mitigate this problem going forward?
Yes, sure, Darren. So in the greater Sundance area, we have six gas plants that for the most part are built right on or very close to the NGTL corridor. When we designed and built those plants, we designed the final compression stage that delivers the processed gas on to the system around historical operating pressures. Those pressures consistently averaged in 6,500 to 6,700 KPA range. Over the past 18 to 24 months, we started to see frequent increases that see the system pressure rapidly rise by up to 1,100 KPA. These pressure swings can happen quickly and last hours or in many cases can persist for few days.
There are three plants that have been affected by these pressure events, those being the Nosehill, Oldman and Oldman North facilities. These three plants typically run at or close to capacity. It requires more horsepower to move the same volume of gas at a higher pressure, so when these pressures spikes exceeds the amount of horsepower we have available, the facility is unable to move in much gas, the impact on production is as high as 3,000 boe a day.
So over the past two and a half months, we have been taking steps to alleviate this problem. In December, we made some piping modifications and repositioned our sales of ESD valves at Nosehill gas plant. So now, we’re able to deliver the full plant capacity at pressures right up to the TCPL meter station contract pressure.
At the Oldman complex, where the two plants are located 11 kilometers west of the TCPL meter station, we are currently installing more pipe to minimize the impact of these increased pressure events. This solution, along with the work done at Nosehill, will allow us to follow unconstrained during these high pressure events.
We’re hopeful that in NGTL looping project currently underway in the immediate vicinity of the recent three plants will reduce the magnitude of the pressure swing. However, if they continue to contract volumes above the capacity they presently have built and have advertised to build going forward. The pressures on the system will continue to increase. And if that’s the case, we will need to invest more capital to install compression. We have completed the engineering on those projects and are poised to quickly bring those projects to the field if required.
Okay, thanks. Hopefully, we don’t have to invest too much more capital to deal with higher pressures, but…
No it just goes back to – you emphasized over the year and we – TransCanada really needs to respond to the system constraints that have plagued the industry for the last two years. Todd outlines the details of it, but it’s a systemic problem and they’re aware of it and we look forward to some action on that front to increase takeaway.
When is the looping teed up for?
We expect November that the line will begin the service.
Construction is underway.
Is that going to affect our service in the interim? Are they scheduling any sort of downtime or anything?
We haven’t seen anything.
Okay, good. Okay, I did have a question here for Kathy Turgeon. We’ve had a couple of changes in our business over the year end. One of them is this new Alberta carbon tax, which some people like to call the hot air tax. And then of course we’ve got this new modernized royalty regime that’s brought into place. Both of them are pushing a lot of additional administration on to the individual E&P companies. And so that ends up being maybe a manpower requirement for stuff we have to track and file. The question came up is there any financial implication to some of these changes.
So, Kath, can you just talk for a minute about these two changes to our business? And do we see anything material in terms of our operating costs or royalty burden as a result of them?
Sure, Daren. Let me just start with the last part first. We don’t expect material changes to either our operating cost structure or to the royalty burden on any wells. Peyto has applied for a platform received all of the necessary exceptions under the Climate Change Leadership Act. Like all other Albertans, we do have to pay the carbon levy on fuel for trucking costs are slightly impacted. However, many of the strategies for cost control that we have adopted or are in the process of adopting such as multi-pad drilling, the new liquids pipeline to eliminate trucking and production and working with our suppliers to use marked fuel where possible, have the added benefit of minimizing the carbon levy impact, which I reiterate is not significant for us.
From an administrative point of view, both of the programs require monthly reporting, which is rather onerous. In the case of the royalty framework, it’s actually double reporting. Year one, we report budgeted drilling and completion costs then in year two we go back and report actuals. We are actually still waiting to see what the reporting for the royalty framework will look like as the government has not yet ruled out a system. Both January and February data are supposed to be reported by the end of March unless the government has further delays.
So depending on this level of detail, we’ll drive the complexity in the process design and reporting that we have to implement. We have already designed and implemented the carbon levy reporting process and we filed our first return at the end of February. We estimate right now that it will require about one fulltime equivalent position to capture, compile, review and report the data. At a time when cost containment is paramount, it is disappointing that these additional costs are being additive to the industry with no basement really.
Big work project for the government, great.
Thanks, Scott. JP, I mentioned earlier that you were going to talk a little bit, can you maybe elaborate a little bit on our Q4 drilling program, the wells that we drilled in the development areas and maybe some stepout areas? Can you also maybe talk a little bit of color on the results for Q4 and what that means for the lineup?
Sure Darren. Our current – our Q4 drilling program consisted of a predominantly development program, I think, in the Sundance area, while we drill a lot step out wells as you referred to the mid-Brazeau area. Our Sundance program largely met our expectations with results that were consistent with the past. Brazeau we were following-up with some great results on our [indiscernible] play earlier in the year. But had mixed results in Q4, as you mentioned, in the opening. And then as a group they underperformed our expectations for sure.
The tool the line-up for the first half of the year have slightly lower mix of the exploratory or riskier type wells than last year. But where we are stepping out on trends that we see seismically, we are drilling vertical, stratigraphic wells first, which are carefully positioned on dark plays like our Faulted Cardium. To lower the risk and confirm the presence and thickness of sands, before we plug back and reenter them with a horizontal. Now all of this take a little longer and cost a little more it should pay off in a long run with improved economic results.
So far this strategy appears to be working and we’re very encouraged with the results we’ve drilled so far in 2017. We do have a lot of wells right now at various points of completion or time. And this is partially related to our continued focus on cost control, and drilling from pads. But we also have drilled few wells a little farther away from our infrastructure that we’re excited to get on stream, some of which will take a little longer to get on as we build out that – build the infrastructure.
Okay. Good I think we’ve got a good lineup after the first half of the year. We got David Thomas, our VP Exploration here. So, Dave one of the questions, I get a lot is sort of about Peyto’s inventory. I think there’s not a great understanding about how we build out inventory overtime, and how we’ve done such a good job with such a small land base.
So, I thought I’d ask this question again, that I get all the time, we added to our prospect inventory last year, we made several small acquisitions, we did some Crown land sales. So that obviously adds to our inventory. So I guess the question would be how much of the 2016 drilling program is targeting these new areas? And maybe how much of it is on the old inventory that we had preexisting prior to some of these new land ads? And what’s the sort of split?
And then maybe secondly, does gas price or the change in gas price that we seen quite dramatically here over the last couple of months does that change how our drilling line up looks for the year?
Darren, the new lands we added in 2016 were mostly in the Greater Sundance area, but some down in Brazeau. At 145 to 160 wells we have plan for 2017, 32 are scheduled to be drilled on the lands which we acquired just last year in 2016. That’s in the neighborhood of 20% of our 2017 drilling program. I should also point out that these 32 locations include 23 development locations in Greater Sundance. The remaining 120 to 130 locations planned for 2017 will come from our existing inventory which at year end 2016 included 1,290 Spirit River and Bluesky locations of which 724 were recognized as booked locations in our independent reserve support.
The main point of mentioning is to reemphasis that our inventory is never static, we are constantly adding to it and the new locations added are a mix that can, that the lands we acquired in 2016, they can include a very high proposition of development opportunities closing to our existing infrastructure.
As to the second part of your question, Peyto will not begin to produce un-hedged volumes into a low price market and we’ll modify our drill plant accordingly but, find out we are well-hedged as you know, and we also have some portfolio of Faulted Cardium locations that are beginning insert into our plant if we need to emphasis the liquids portion of the program a little more.
So how is that Dave is, we bought new land, which we think that wouldn’t fall under sort of the pure development category just because new lands would be expected to be further away from infrastructure maybe more step up more exploratory in nature. But you are talking about we’re buying even individual layers within developed areas, but we didn’t know them before that we’re now developing or...
It can be a real mix Darren as for the lands closer into the Greater Sundance area that’s up in the case we were successful again acquiring some of the acreage perhaps below the Cardium that we didn’t have the control over before. And due to the positioning of our infrastructure, these locations are often very economic for us to drill and we sought them right into our program and can drilled them very, very, very quickly. So it’s not a surprise to me, so I would say that 20% of our drilling program for 2017 is based on land. We just recently had. And we typically don’t have that big land bank as we sit on for ages and ages. We’re usually on top of the land that we know we can tie quickly, very fast.
So a bit of just in timeline strategy?
It’s – for this stuff that’s quoted in, we can flat that in. And it’s a little bit harder, I should point out. The last year or so, the timelines that that are imposed on us by the regulatory environments here have grown. We used to be able to react extremely fast and now these timelines are being pushed out by several months. So I think we believe we’re still nimble, perhaps more so than many of our other competitors, but I think we’ve lost a little bit of that hedge, which we enjoyed when the regulatory environment was perhaps not so cumbersome.
Yeah, so hopefully some changes there at the AER will help to bring some of that efficiency back to the table. Thanks, Dave. So speaking of land, Tim, as our VP of Land, you do a lot of analysis on the land sale activity. I would say that’s going on both in Alberta, where we are. You look at BC2. I am just wondering if may be you could provide some comments and some color on land sale activity over the two provinces over the last a little while. And maybe also what Peyto’s participation has been in these land sales, prices we’ve paid to get some of the current land that we’ve picked up in recent years.
Sure, Darren. To be fair about the comparison of land sale activity between our program BC, we should only discuss public offers within Alberta, where petroleum and natural gas rates are involved. So in other words, figures for oil sands dispositions should be excluded. Historically, Alberta has always tendered more acres annually at Crown land sales versus BC. And we should be no surprise giving the province wide oil and gas activity within Alberta versus BC activity being constrained mostly to the northeast corner of the province plus there are 23 to 24 land sales annually for Alberta compared to 12 sales per year for British Columbia.
[Indiscernible] more acres, you would assume that Alberta would collect more bonus revenue than BC. For the most part this has been true with the exception of three years from 2007 to 2009, where the annual uptick from BC sales surpassed Alberta’s. The historic high mark for BC was in 2008, when industry spent $2.6 billion primarily for the Montney and Horn River plays. The all-time high for Alberta was in 2011 when $3.5 billion was collected.
The primary players is creating this type of expenditure would have been the Duvernay and Montney. Over the last two years, both provinces have experienced significant decreases to their annual land sale revenue as a direct result of low commodity prices. In 2016 both provinces encountered historic lows. Alberta collected $136 million whereas BC only collected $15 million. And it’s interesting to note that for the data I analyzed since 2000, the average dollar per acre acquisition cost has always been higher for BC compared to Alberta.
Now with respect to Peyto’s participation at Alberta Crown land sales, we have always remained an active purchaser. Over the past five years, Peyto has spent $36.3 million at Crown sales to acquire over 134,000 acres, which equates to 210 sections. You have to remember that Peyto is not a company that acquires exploratory lands for the sake of having more yellow squares on the map. And as Dave alluded to in his discussion, Peyto acquires lands where we have identified drillable locations.
So what does this leave Peyto with respect to acquisitions in the future? Despite the low commodity prices, Peyto is still able to complete effectively at crown sales due to our low cost structure. We have had a good start to the year with the acquisition of 33 sections or just over 21,000 acres at Crown sales thus far. And we’ll continue to work on asset deals as well in order to supplement our drilling inventory.
Thanks, Tim. That’s some good color on land sales. I just got a couple more questions. I wanted to get on. Maybe Lee I was hoping may be you could comment on some of the improvements that we’ve seen in drilling performance. I had a slide in our corporate presentation that looked at the drill curve that has evolved over time and we’ve made some big gains there. But I suppose some of that’s technology some of that’s practice, maybe you can comment on the horizon. What are we looking at? Is there anything new coming down the pipe in terms of new technology or something that could effectively change the drill curve for cheaper faster wells?
Sure, Darren. Certainly, we’ve had a lot of practice having drilled over 700 horizontal wells since 2009. Looking back to that era, our Spirit River horizontals in the Sundance field occupied an average of 34 drilling days at a cost of about $3.2 million. Now back then that was certainly considered top decile performance relative to our competitors. And today, we’re accomplishing these same drills with on average longer laterals in 15 days to 17 days and cost of about $1.7 million.
Similarly, in Brazeau, our performance gains have been equally noteworthy. Our program there began in 2013 where our Spirit River horizontals were taken about 35 days at a cost of nearly $4 million in comparison to our recent round of equivalent drills and under 18 days in the cost of $2 million.
Now, although we incorporate continual stream of applicable new technologies, things like drill bit designs, and mud motor advancements and agitation tools and a list that could really run on and on. We’re always very analytical prior to implementing any new tooling simply because it’s something new on the shelf and available to us. The fact of the matter being the bulk of our performance gains have been and are expected to be in the future, a direct result of our experience.
As mentioned previously, we’ve had a lot of practice. And being an active operator through the past couple of years where most of the industry was stagnant we’ve gotten very good at execution where less active players may have remained static in performance.
Throwing a heap of capital towards high costs new technology simply to save days doesn’t always actually equate to saving money. And take, for example, drilling rigs, there tends to be much discussion around the latest generations of AC drilling rigs complete with walking systems and bells and whistles. For the most part with some minor tweaks to things like pumping horsepower and top drive systems, we utilized the very same conventional rigs that we’ve been using since the beginning of all this.
For that matter our top performing rig in the field has been in the Peyto fleet since 2009. The capital to construct these latest generation drilling rigs has nearly doubled that of a conventional Peyto style rig. And for that given contractor should anticipate a substantial day rate uplift to warrant that doubled investment.
Our primary focus is and will continue to be on execution and we’ll keep mindful eye of new technologies as they come to offer, but we’re going to focus on those ones that will help to enhance our reliability. This simply puts a fancy new pair of skates and a $300 hockey stick on a young hockey player isn’t going to make him tomorrow’s Connor McDavid. And although applying the right technology at the right time is critical. We’ve proven those gains to be more about our operational focus.
Are you saying that I can’t buy a better game?
[Indiscernible] I can tell.
You spent too much on golf?
That is Connor McDavid’s stuff that doesn’t belong here.
All right, I just want to ask one more question here before we open up the lines to all the listeners. We had a question coming overnight about our hedging practice, that’s changed a little bit. The future shift has changed dramatically. So the question that came in overnight may I’ll ask this to Scott Robinson, our COO. Scott, there’s been a big change in the forward curve. It’s gone from a contango curve to backwardation curve where the price is not climbing anymore now. It looks like its falling. So how does that affect our hedging strategy? And are we going change the way that we’re hedging going forward?
It doesn’t really change anything to be honest. And may be I’ll just talk about our strategy just to reiterate how it fits in and expand on what Dave talked about the confidence of our program. Our strategy to hedge has been paramount to us over the past and that’s going to continue to be so. If you look over the last 10 years, the strategy has worked very, very well, smoothing out the price swings. And it’s allowed us – it’s given us the confidence to undertake capital programs, particularly this horizontal well regime. It gives us the confidence that the returns – that we’ll get returns from those projects.
If we look at the entire – over the last ten years of hedging, we’ve actually made over $400 million gains, which is a testament to keeping good pricing during the period of which the shale revolution has brought natural gas prices down for that period of time. If you look at our wells, and JP has spoken about this in the past, we’ve got about a two-year to three-year payout range on the wells. So the initial year is pretty important to understand the investment outcome and reduce the risk.
And for example, if we look back at this immediate year 2016, we spent about $360 million on the wells we drilled. And we recovered about $110 million on the cash flow from those new wells, which was largely underpinned by our hedging program during that period last year with very, very little gas prices. We had adequate pricing in place to give us hedge gains to provide the pricing necessary to make good returns and that resulted in roughly a third of the capital coming back to us in that year and that’s consistent with the two year to three year payout.
So getting a hedge program for the purpose of capital confidence is a pretty key. We look forward to 2017. We’ve got a very fulsome book as Dave alluded to, about three quarters of our current production is hedged at about $2.60/GJ. Interestingly and as you pointed out and our MD&A points out that that position was in a loss position at the end of the year because of a very momentary high price – high strip price situation. Our book is about $150 million loss, but through a dramatic price fall. In the early part of this year, we now have a book gain mark-to-market gain of about $40 million.
Those are interesting, but that just goes to show how much volatility can occur in amongst that price which was $3.28 at the end of the year that lost a dollar in one month. Our 2017 price for the most part is locked in at $2.60/GJ. And that gives us the return that we want from the program that we can now continue to confidently embark on. So those dynamics demonstrate just how valuable, consistent and unbiased hedging program is and we’ve actually enhanced that program this year.
We’ve extended our hedge horizon two to three years. So we’re just now beginning to see part of picking hedges in the 2020 year and the magnitude of our hedging. Now we’ve got elevated that slightly such that when we arrive at a given season, for instance we’re going to be arriving at the 2017 summer season here, we will endeavor to have ourselves three quarter hedged and we’re right above there right now. And during that season, we may actually take that from 75% up to 85% over the course of the season.
So solid hedging program that served us well and that we still even more so we believe in and we put it in place, it’s systematic, it’s unbiased, it’s not speculative and it fits with exactly what we’re trying to do with generating profit.
Yeah, you bet. All right thanks for the color. Brian, maybe we can open it up to questions from the listeners now.
Okay, thanks, Brian. I appreciate that this is an incredibly busy week and there’s a lot of guys reporting. So there are probably four or five conference calls going on in every office of every analyst around town. So hopefully some of our discussion has provided a little bit of color. As always come to the Peyto website and have a look at the corporate presentation, have a read of the monthly report I post every month with some additional color on our activities as they go throughout the year. We’ll be putting up the March monthly here right away and we’ll have a busy first quarter that we’ll be finishing up at the end of March, but by no means, mean we’re stopping.
We’ve got a rig fleet plan to drill through break up this year trying to take advantage of some of the cost savings that we see during break up. And then I think we’re fully expecting that the industry activity is going to peel back a little bit with recognition of where the commodity prices are. And that’s going to just give us all the more reason to take advantage of the cost structure that we have secured and push forward with sort of the 250 level hedges that we’ve got that we make a good return on.
So I think we’ve protected on a lot of the – protected ourselves and our shareholders on a lot of the risks that presented themselves for this year. We’ve learned a lot over the last couple of years about where some of those risks lie. And I think we’re very well-protected going forward to execute this capital program that we’ve got in front of us.
So thanks for listening in. And we’ll be back with the first quarter conference call in May, I guess. We’ll talk to you then.
Ladies and gentlemen, thank you for participating in today’s conference. This concludes today’s program. You may now disconnect. Everyone have a great day.
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