Peyto Exploration & Development Corp.

All right. Well, thank you, Melanie, and good morning to everybody calling in, and welcome to Peyto's Third Quarter 2014 Results Conference Call.

With me in the room today, we've got the entire Peyto Management Team, consisting of Scott Robinson, our Chief Operating Officer; Kathy Turgeon, our CFO; Dave Thomas, our VP Exploration; JP Lachance, our VP Exploitation; Tim Louie, our VP of Land; and of course, we have our Investor Awareness Rep, Jim Grant, with us today as well. And Jim, I see you've collected a bunch of questions from shareholders.

So why don't I flip it over to you?

Okay. So for those of you who are new to our conference calls, we hold the first half as a question-and-answer session, where I ask some of the senior management questions about Peyto and its latest financials before we turn the call over to questions from investors and representatives of investment businesses.

So Darren, for several years now, as we've presented our third quarter results, we've talked about how we're in the home stretch of our biggest year in terms of organic growth, but that we're planning an even bigger one next year. How do we stay the lean and focused organization we are as we continue to scale up our capital plans?

Yes, Jim. We were laughing at the board meeting yesterday -- sorry, the day before that.

Every quarterly release lately seems to start off with record quarterly results, which is pretty neat. And you're right.

We are a very lean and focused organization. And it's really, I think, quite amazing what we're accomplishing with only 48 full-time staff and a handful of consultants here in Calgary and then our dedicated field guys.

I mean, consider the fact that over the last 5 years, we've invested over $2.5 billion and grown production from under 20,000 barrels a day to 85,000 barrels a day, that -- with the team that we've got. That's just awesome.

That's, I think, almost unheard of in this industry. But one of the reasons -- the big reason I think that we can do so much is that we always have a very good game plan, and the risk that we don't get what we're planning is actually very low.

We've always stated that our strategy from day 1 has been low-risk, repeatable, predictable returns. And when you think about it, when you're scrambling around, trying to figure out how to deal with some big problem or figure out why things didn't work out the way that they were supposed to, that takes a lot more people, and it knocks you off your game plan, and it distracts you from your goals.

And we rarely have to deal with that. Now some might say that being so predictable and being so repeatable and low-risk is boring because then we're not using the latest, greatest technology that they can't write about, and we're not chasing the hot new play.

But quite frankly, I don't care. I mean, low-risk, repeatable, predictable, that's how we're able to accomplish what we have with this lean and efficient team.

Okay. Turning to Scott Robinson, our COO and VP of Operations.

Scott, we're hearing a lot from other operators about gas processing and transportation system constraints. Has our production suffered from some of the same impacts?

Can you provide us with an update on production?

Yes, Jim. Why don't we start with the second part there.

That's the really good news here, our current production. The growth, as Darren stated, we're about 85,000 or thereabouts now, but the growth has been very impressive.

And if you take it apart and look at it over last several months, to recap, we started Q3 at about 72,000. We grew to 80,000 barrels.

And then, more recently, we've made another quantum jump to about 85,000, 86,000 barrels a day thereabouts on a daily basis. Our drilling and our facility projects have really fallen into place very nicely, and they've enabled us this continued growth.

In fact, this past weekend, we completed a fairly important project, the connection of our South Brazeau acreage to our gas pipeline, a long pipeline. It's very strategic, and it allowed us to take this most recent jump in production.

If we go back to the first part of your question, the system outages and constraints that have plagued many of the gas producers out there, I believe they haven't really had that same impact to us. It's not to say that we haven't been immune.

We have had some NGTL cutbacks where we've had to cut some plants back, but by and large, it hasn't had the same impact. I think that's largely because of our strategy.

We control -- own and control our facilities. They're all more or less situated proximal to the main gathering lines in the province, the transmission lines in the province, and this has enabled us to keep our run time up at that 98%, 99% level, which is critical to delivering the results that we're doing.

Okay. Turning to Dave Thomas, our VP of Exploration.

Dave, your efforts a few years back led us to the large flag positions we have at Brazeau. With the drilling and infrastructure investments that we have made over the last 12 to 18 months, can you comment on how the resource -- results have measured up to your original visions?

Jim, shortly after Peyto became involved drilling the Wilrich, we began looking for areas we could capture more of the play. Brazeau down in Township 4412, West 5 was the southernmost location we evaluated.

But we also recognize that in addition to the Wilrich, the area had good multizone potential, similar to our main Sundance core area. So over a few years, we gradually built the land to this now over 100 sections, bought a lot of 3D seismic, and we've now built some significant new infrastructure.

And we've also been busy drilling our initial wells. At North Brazeau, which is the shallowest end, has the easiest access, we've now drilled 8 Wilrich and 2 Upper Falher tests.

So the Wilrich results have been similar to our Sundance, Nosehill Wilrich wells, but we were disappointed with 2 wells drilled to test the Upper Falher. This year, we all also tested the deeper, thicker, higher-pressure Wilrich in the Southern Brazeau area.

And we've been very happy with the results. The first well, the 212, 4213 West 5 has been tied in and is now on production, and we have seen a good step-up in productivity.

Reservoir pressures down there are over 42,000 kPa or 6,100 psi. And it's similar to the step-up we saw after moving from shallower Wilrich at Nosehill to the deeper, higher-pressure Wilrich at South Obed and Ansell.

In addition to 212, we've also drilled one more follow-up Wilrich at South Braz and also at Middle Falher, both of which looked very strong. The Middle Falher will be very important to watch as there's a tremendous amount of this sand here.

So 2015 is looking to be an exciting year down at Brazeau as we make more headway towards developing the over 300 Spirit River drill locations we've identified here.

Okay. Turning to JP Lachance, our VP of Exploitation.

JP, we've mentioned in our press release we've made improvements in our operational execution this year. Can you elaborate on this further?

Thanks, Jim. There's a table in the press release that shows some average well drilling data on our year-to-date program as compared to the last 3 years.

It's important to point out that, despite the fact we're drilling consistently longer horizontals year-over-year, we're also getting them done cheaper. The typical 4,000-meter well back in 2011 drilled today now costs us $400,000 less.

This is more impressive when you consider that this year's drilling program includes some more costlier wells down in our Brazeau area. If we look, then, at our Sundance area in isolation where we still have a vast inventory of Spirit River locations, average drill costs are down under $2.5 million for those species with individual well costs routinely coming in, in the $2.2 million to $2.4 million range.

But that's not to say that we've not moved up the learning curve in Brazeau. We now have shown that we can drill wells there for under $3 million, which is a vast improvement over the earlier wells.

On the completion side, costs are relatively flat over the last 2 years, which is good, considering we're fracking more stages with the longer horizontals and the increase in density on some of our species. Well production results look better for our 2014 program on average, so -- as compared to previous years.

So this, combined with lower costs, translate into better expected returns for this year's program. It's this focus on cost control and improvements in operational efficiency that allows Peyto the ability to make good returns even in low-price environments.

Okay. Scott, in our second quarter conference call, you spoke about the infrastructure that was planned to connect the results of our activity in South Brazeau to our nearest gas plant.

Can you give us an update on the Brazeau infrastructure and its impact as well as an update on our other facility and infrastructure projects that we are completing as 2014 wraps up?

Yes, Jim. We already mentioned the Brazeau line that's quite a feat, recently came on stream this weekend.

A lot of people involved in that, and hats go off to them for accomplishing that -- building that line through some very challenging terrain. It's going to be a very critical line.

It takes us right through -- this is a gas collection corridor, right through the heart of our acreage position down there. And in the near term, we're going to drop in another compressor there, too, so that'll pump up the capacity in Brazeau.

In addition to that, we've got a couple of other compression expansion projects, which in total -- all total with some of the existing capacity gives us about 9,000 barrels a day of growing room -- immediate growing room in the areas where we're currently drilling. So we'll see how much of that space we can fill up over the rest of this year.

Okay. Turning to Kathy Turgeon, our CFO and VP of Finance.

Kathy, can you give us some background on what factor or factors have been steadily dropping our interest costs per Mcfe over the last year? And where do we stand at the end of the third quarter in 2014 between our credit lines and our senior notes?

And what credit is available to us as we look forward to another record-breaking year of growth?

Our interest costs on a per Mcfe basis have been declining over the past quarters from $0.25 per Mcfe to our current $0.20 per Mcfe. However, as rapid volume growth affects this number, it's more informative to look at interest costs on an average interest rate paid basis.

This has also declined from a high of 4.3% in Q1 2014 to our current 3.9%. And this is really due to 3 factors: one is a layering in additional $50 million tranche of senior notes at 3.79%.

There is also a reduction in our debt-to-EBITDA from over 2.1% in Q1 to under 1.5% to 1% in Q3, which allows us to pay lower stamping fees on our drawn amounts in our bank lines. And we've also seen an overall lowering of our stamping fees and unutilized fees on our bank lines that were negotiated in our latest credit agreement in April 2014.

At the end of the quarter, we had drawn $565 million on our bank lines, which is out of $1 billion available. And we also had $320 million in senior unsecured notes.

As we go forward to another year of growth, we can use current available room on our credit facility and are also well positioned to access additional financing by either expanding our current credit facility or issuing additional senior unsecured notes or both.

Okay. Darren, can you speak to our overall strategy with respect to capital spending, raising equity and using leverage to rightsize our growth while balancing it with the requirements of being a dividend-paying corporation?

Sure, Jim. Yes, that's a question I get a lot, and I've sort of written about it in the past in my monthly reports.

There's times, arguably, when we want to be more aggressive investing shareholder capital because we know that those are the best times to be generating the maximum amount of return. And typically, those are when we're in an off cycle, which affects the commodity prices, industry activity is down, costs are down, so sort of countercyclical to the rest of the industry.

And in those times, we want to be as aggressive as we can, so we use cash flow, debt, equity, all funding sources to put the maximum amount of capital to work at those times because we know that's when we can generate the best returns. And then there's other times when costs are high and activity is really high, and those are typically the wrong times for us to be investing capital when we're really challenged to make those same returns.

And so we pull back capital programs. We paid down our debt.

We dividend out more to our shareholders. And depending on what environment we're in, the numbers aren't always going to balance out.

So sometimes we'll be spending more than we're making, and other times, it'll be the opposite. But what's important is if you look at Peyto over the long term, like say, the last 15 years, for instance, and then you see that the numbers truly do balance out.

I think in total, we raised about $1.3 billion in total amount of equity. And we paid out, I think, $1.6 billion in dividends and distribution.

So we paid back even more than we've ever raised. And then we have a little over $900 million in debt.

So I mean, if you net that out, arguably, we've used about $600 million of debt to build a company that has a market cap of $5.5 billion. I think, arguably, that's exactly what you want.

I mean, we've built the majority of our market capital, almost all of it, out of our cash flow. And that -- as a shareholder, that's the most accretive way to create value.

So along the way, we've seen significant and sustainable growth in our asset base and in our profits. And of course, we share a little bit of that profit with small dividend increases, like we just did.

Dave, over and over, we speak to our large inventory of drilling locations. Can you give us an overview of how the work of identifying or prioritizing these goes as we plan out next year's ambitious plans?

Jim, one of our top priorities is always to protect Peyto's cost advantage. When we ramp up our capital spending like we've been doing, it's a more complicated process than just turning up the dial a few notches to add more rigs and drill more wells at a faster pace.

Of course, we'd like to always drill our better locations first, but we have to be aware of the other considerations. We don't like to strand our gas, so we have to look at how much available gas plant capacity we have or when a new compression is being added or how much room is in our sales gas line or is a TCPL meter station expansion needed.

Matching our drilling projects to our infrastructure projects is very challenging, and some companies achieve this better than others. We seek to maintain a good balance of projects across several play types to balance risks and not to exhaust any one stable of opportunities.

And we like to hold some of the drilling locations in reserve that are close to high-grade roads to use during spring break up. Other locations may need to be drilled to satisfy land tenure agreements, to hold the land and keep it from expiring.

We also prefer to space out our higher-risk exploration wells. Adding new rigs also means adding new people, both in the field and in the office.

These people will be new to Peyto, new to our Peyto corporate culture, and there is risk to bringing in too many new people too fast. So in general, Jim, prioritizing our drilling projects is not a cut-and-dried process, especially when increasing our capital spending.

It's a pretty evolved process that -- and it's a lot more complicated than just ranking them by rate of return. So far, we've been quite successful at it, but there's a lot more to it than meets the eye.

Okay. The next question goes to Tim Louie, our VP of Land.

Tim, from time to time, you've commented on the tenure on how land auctions are going. Given the roller coaster ride of recent oil and gas prices, how are current auctions?

Are we seeing a lot of interest in the lands we would like to acquire? What about the flip side?

Are those companies with expiring lands behaving any differently now this time -- than this time last year when it comes to finding ways to profit or at least not lose out on lands that are about to expire?

Thanks, Jim. The total bonus paid and the amount of acres disposed at this year's sales still lag behind those values from a year ago.

However, the trend of higher average prices has continued on. Although we are seeing increased competition in the form of higher per acre bids, we have been successful on acquiring 34 sections within our focus areas.

With regards to companies with expiring lands, we haven't seen a noticeable change in behavior. Unfortunately, there are a lot of companies that are not motivated to sell or farm out expiring acreage.

Although we try to negotiate deals on prospective expiring acreage, we typically have to wait for these lands to expire, and then post the lands for a future sale. That said, thankfully, there are some companies that are prepared to capture value from their expiring lands.

Earlier in the year, we acquired 6 sections in the Brazeau area. We negotiated modest purchase price since the lands were due to expire in 9 months.

And because of our ongoing drilling activities, we'll have no problem to continue these lands.

Okay. JP, in our latest news release, we are announcing an even larger budget for drilling and other capital spending than this year.

Can you speak to the operational plans, including your strategy for the next spring breakup season, and this winter's activity in those areas where we can only -- that we can only access during the winter?

Jim, our capital plan for 2015 contemplates about 117 to 130 net wells next year, which based on our current drilling performance, would require about 9 to 10 rigs working most of the year. We demonstrated this year our ability to work effectively through breakup in our core Sundance area.

So we're already planning wells for 2015 that we can drill during the period, utilizing our existing roads and leases. We can't drill through breakup everywhere we operate, so we'll likely have some rigs down, like -- in areas like Brazeau, for example.

We don't have a lot of areas where we can only access in the winter, but certainly, there are some that are cheaper under frozen conditions, and those locations are already surveyed and will be ready to drill. Our program next year will focus, for the most part, on the mix of Wilrich, Falher, Notikewin, Bluesky and Cardium wells selected from over 1,700 locations in inventory.

We plan to drill all the way along our land basin, our Deep Basin from Cutbank down to Brazeau. We've tested our type curves using full-cycle costs against various prices, and we feel confident and comfortable that our prices are -- that most of our wells planned for next year make us a positive return, even at $3 gas prices.

Well-related costs make up about 80% of our planned budget next year, but we also have a significant amount, about 17% of the total, for our facility projects already underway to add pipelines and additional processing capacity of 120 million cubic feet a day. That may seem like an ambitious plan for 2015, but the Peyto team has already proven this year we can successfully deploy a $700 million program.

So we look forward to spending even more into the business environment, and the results are warranted.

Okay. Scott, the Q3 operating costs dropped from the same quarter last year and from the first 2 quarters this year.

What factors contribute to this? And what do we see on the horizon for operating costs?

Yes, costs, they're really good. They're where we want them to be.

We're very pleased this last quarter to bring it down to the lower end of the range that we've seen over the last few years, the current quarter being about $0.33 per Mcf equivalent or $1.95 per boe, when you convert. So we're pleased with that.

The reduction. What's causing that?

It's -- there's no one factor, really, 3 main things. We did -- as we mentioned earlier in the year, we accelerated some maintenance, and we stocked up on some chemicals, which lessened the need to do so this last quarter.

So that was one contributing factor. We spoke of our significant production growth, so that certainly helps reduce the fixed cost portion of our operating costs.

So those things and some specific efforts in other areas that I won't go into detail, but it's a sacred part of our business. We've always said that.

And as we look forward, I don't see any reason why we shouldn't be able to maintain this level at that $2 or less per boe basis, particularly considering some of the growth plans that we have in front of us here.

Okay. Darren, many of our investors, and those working for investment and other financial business, model our growth and performance.

What would you suggest are the key elements of our business that can be modeled based on what we have done in the past and foresee in the future? Are there any elements of the traditional E&P modeling that you think do not apply to us?

Yes, Jim. Everybody, I think has a model on Peyto, which hopefully we're blowing away all those models.

As I've said before, I personally think it's the repeatability and predictability of what Peyto does that tends to surprise a lot of guys to the upside. Low-risk, repeatable, predictable.

That's the stuff that delivers the results for us, and we've done that now for several years. So I would suggest that the old adage that past performance doesn't guarantee future results, maybe doesn't apply so much to Peyto.

And if anything, practice is making us perfect. I mean, we're getting slightly better every year, as we continue to do more of the same thing every year.

So I mean, I would suggest that it's reasonable to expect that we're going to be even better next year over this year. The oil and gas industry, though, is somewhat fraught with risk, and most people that are modeling oil and gas companies tend to layer on a healthy dose of risk.

But again, I think we're much lower risk. We -- our assets have less risk in terms of recovery, in terms of their costs.

Our future opportunities have less risk in terms of the repeatability of what we've been able to do. And I think our strategy has less risk because we're not changing it, we're just getting better at it.

So the risk that you would apply to the future of lot of companies, I wouldn't apply that kind of risk to Peyto. We have much lower risk.

Right. So Darren, as you look forward to our ambitious plans for 2015, what are the milestones that you think will be important to judge how well we are executing those plans?

Well, like the guys talked about today, I think it's going to be all those same things that we're going to be looking for. We're going to be looking at drilling and completion performance.

We're going to be looking closely at the production results. Scott suggested that we're going to be looking at our costs and trying to control those cost pieces as much as we can.

We're going to be watching our profit margins, our operating margins. We're going to be trying to maximize our run time at our facilities.

As Dave has talked about, the timeliness of our production additions relative to our capital spending, those are things that we're watching. And all of those things contribute to the IRR, the returns that we're delivering on every dollar of shareholder's capital we're investing because, I mean, at the end of the day, that's the point of our business.

How much profit can we generate on the capital that we're using. That's what we're focused on.

And so we're not going to take our eye off the ball. We have a game plan, and we know what it's supposed to deliver, and we're going to be looking exactly for those deliverables.

Okay. So Melanie, at this time, we'd like to turn the call over to questions from investors and representatives of investment businesses.

I just want to ask a couple of follow-ups on Brazeau. I think you mentioned 300 potential locations at Braz.

Just a little bit of clarity into those numbers. Are those 300 at Southern Braz or all of Braz?

And then if you could break out those by species -- by Wilrich versus Falher?

The 300 locations are situated with -- over our entire Brazeau land base, and the majority of the locations are Spirit River. And to split that up more, most of those are Middle Falher, followed by the Wilrich and then the Notikewin.

There are also a smaller number of Cardium opportunities. And in the future, there may be some Belly River.

But the vast majority are Spirit River opportunities and the Middle Falher, as I mentioned before, which has been tested by other companies north of our area, and we just tested it in the South Brazeau. It's a very large, mappable in-size valley full of sand, and that's going to be a really exciting area for us to drill this year.

Now remember, Kevin, those aren't booked locations, so that's our own internal estimate on the lands. We haven't had the independent reserve evaluation done yet to this year.

That'll be done at the end of this year. Last year, we didn't have a lot of locations recognized in Braz just because it was still very new for us.

This year, we've done a substantial amount of drilling there. So that's helped prove up a lot of opportunity, both proven undeveloped and probable additional opportunities.

So Braz will see quite a big change, I think, in reserve bookings this year, but again, those 300 locations are internal at this point.

Okay, great. And then my other question here is just with the recent oil price weakness over the last few months.

Have you noticed or seen any leading-edge indications of service cost deflation?

Not yet. We -- earlier, when oil price was stronger, we were hearing hints of potential small increases coming into the winter here, and some of our service providers have backed off on that, suggesting that we shouldn't see those costs that they might have, at one time, anticipated.

So looking at it at this point in time, we're assuming that our cost structure will more or less be consistent through the winter to where it has been here the last few weeks.

One of the things, Kevin, that might show up much more quickly with the fuel surcharge is if this lower oil price translates directly into lower diesel cost out in the field, then that's something that we've been fighting for the last several years is the cost of fuel. But the other rates and stuff are going to be dependent on activity levels in a way, and so -- I mean, winter is typically the busiest time of the year.

It probably will be the hardest time for us to start to see a downward pressure on activity because of the commodity price.

Okay. Thanks very much, Melanie.

Realize this is a busy morning. Actually, there's been a lot of news coming out last night and today.

So everyone is probably scrambling to read about it. Ours is good.

So we're happy about that. I'd like to put out a big thank you to the entire Peyto team, another stellar quarter.

So a great, big thanks on behalf of shareholders and the board to the Peyto team for their efforts. Obviously, this is a pretty amazing team that we've got here at Peyto.

To use the sports analogy, we've got a lot of talent on the team, and we're playing with a lot of confidence right now. So that's a pretty deadly combination, typically in the sporting world, and I think it's a pretty deadly combination in the business world, too.

So we're excited about our fourth quarter, and we'll be back to you in the new year to talk about it. We've got some big plans ahead of us.

So we're ready to all get going here. Anyway, we'll talk to you next time around.

Thanks for listening in.