Peyto Exploration & Development Corp.

Great, well thank you Wayne and good morning everyone. Welcome to Peyto’s first 2015 results conference call.

This is obviously a very busy week of reporting. So, thanks to everybody for calling in and joining us this morning.

Before we get started, I wanted to send out a big, big thank you to the Peyto team here for another fantastic quarter of results. They continue to challenge the status quo and continue to drive costs down and of course that makes Peyto and its shareholders even more profitable and arguably even more resilient to the changing commodity prices and possibly changing fiscal regimes that we might have up in front of us.

So, big, big thank you to them. In the room with me today, we have got the whole 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; Lee Curran, our VP of Drilling and Completions; and Todd Burdick, our VP of Production.

Of course, we also have Jim Grant, our Investor Awareness representative here and Jim I see you have collected a whole bunch of questions, so why don’t we turn 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.

Darren, while commodity prices have been challenging particularly with liquids and despite the limitations imposed on us on the amount of gas we can put in the pipeline system, we were as active as we were in the first quarter of 2014 drilling 31 wells in the first quarter of 2015. Are those activity levels justified given the current commodity price and are they justified if we aren’t sure we can put the production into the pipeline?

Yes. Jim, we had obviously some pretty low propane prices, in particular, in the quarter.

Those weren’t very nice and obviously we have some issues with TransCanada pipeline or they have some issues arguably with their pipeline and their ability to take gas from us. But both of those issues are very, I think short-term issues.

And we are not investing capital for the short-term. We have got to remember we are investing capital for the long-term value creation here and also the commodity prices and the takeaway issues, I think are going to sort themselves out here quite shortly.

So, what we really have to remain focused on is the fact that today we are taking advantage of much reduced capital cost. I mean, that’s the real opportunity here the fact that we have got 20% off in terms of service costs, we are able to drill wells, complete them, bring on new production for 20% less to-date.

A few months of delaying production, few months of lower propane prices don’t have nearly the same effect on the total return as the reduced capital costs do at the front end. So, I mean, that’s the real goal and so that’s why we are still full steam ahead here.

Okay. Turning to Todd Burdick, our VP of Production, Todd, we noted in our Q1 release that volume constraints on the TCPL system have hampered our production.

Can you summarize the nature of the constraints and what we expect for the balance of the year?

Yes, sure, Jim. So, since December 2014, there has been an ongoing curtailment related to pipeline integrity issues and a temporary pressure delayed in some areas.

So, that has restricted shippers to their firm service, plus 30% of their December nominated interruptible service. Additionally, in Q1, there were separate more extensive curtailments because of compressor maintenance.

That cuts shippers back to firm service only for 20 days. Coming out of those maintenance curtailments, the ongoing integrity related curtailment was then dropped to firm service by 20% of interruptible.

In the near-term and I am talking specifically about Q2, we will see more curtailments restricting us to firm service only and restricting us to about 80,000 BOE. If the schedule holds that could be as much as 24 of the 91 days in the quarter.

And looking beyond June, there is a few maintenance curtailments scheduled to the rest of the year and TCPL have indicated that the integrity curtailment should end around September 30. We are hopeful that with declining production and storage injection, the degree of curtailment after May will be minor to inconsequential.

And they should add that we expect our firm service to increase by 10,000 BOE a day for June and we also have a tranche of firm service in November and that will add 3,800 BOE a day.

Okay. So, Todd with the transportation constraint, what has been the producing strategy to cope with the limitation in light of ongoing drilling of new wells?

Well, Jim there has been a few options we have depending on the particular area, plant and well rate that we are dealing with. In the Greater Sundance area we have the flexibility to move service from one station to another.

So as production declines in one station to below the prescribed curtailment volume, we moved service to another station where we have wells coming on production. We also physically have the ability to swing gas from one plant to another to make room for gas coming from new wells.

And then finally our general well producing strategy has been to produce the new wells while restricting or shutting in older wells in order to meet the levels of allowed transportation. The older wells typically have higher operating costs per unit of production.

So in a context of an already difficult situation, we use this as an opportunity to save money.

Okay, turning to JP Lachance, our VP of Exploitation. JP, can you comment on how the new wells brought on in 2015 so far the 21,000 barrel of oil equivalent a day of additions we identify in our first quarter news release compared to like wells of the past programs?

I think Jim as Todd mentioned, we are bringing on all our new wells. So we are getting good look at the capability.

And so far quite pleased with the results, when we build our capital budget, the production forecast is based on a combination of type curves from prior years. And so far in 2015 we are greater than 4,000 BOEs a day ahead of our estimated growth forecast.

When I look at the average performance of our 2015 wells against our 2014 and 2013 programs, our average 2015 well is about 200 BOEs a day ahead of the average wells in those past programs at the 30-day mark. Not every well is ahead of expectations, but our overachievers are coming from all across their land base throughout the Spirit River strata and with Brazeau, Wilrich, Ansell, Fahler, Notikewin and Greater Sundance and both for Wilrich and the Noitkewin have all contributed to our early success.

The better result can be attributed to falloffs and some more successful discoveries last year and some targeted extensions towards proven areas. So far we are we are off to a good start Jim.

Okay. My next question is to Lee Curran, our Vice President of Drilling and Completions.

Lee the first quarter results news release speaks to a drop in cost to drill and complete wells as well as an increase in the average horizontal lengths of the wells drilled. Can you provide some specifics on the most recent wells with some idea on how service cost reductions have progressed from the beginning of the quarter to to-date.

Additionally can you comment on whether or not some of the savings are the result of changes in our methods?

You bet Jim, so present depressed activity levels through our industry has made for some active competition in service sector. And although those pricing reductions that come with this level of competition is only one component of our cost structure decline.

It certainly has been the most significant factor. As illustrated in our first quarter release, average cost indicate reductions of 8% and 15% respectively on drilling and completion operations on a per well basis.

This includes two operations that experienced significant difficulties early in the quarter, one of those in Brazeau and one in Pedley. The elements comprising total cost reductions consist not only of service cost reductions, but also performance improvements and technical program revision.

The average drill days have continued to decline through the first quarter by approximately half a day per well on an average. However, when looking at our core Sundance area, these performance gains have been much greater with average drill times in the first quarter are now averaging approximately 18.5 days, which is down nearly two full days as compared to 2014 and down one full day as compared to our previous quarter.

Technical revisions have a mixed effect on our total well cost and although many of those elements result in a cost reduction others do result in a slight cost increase. As reported our average drill depths continues to increase.

Of course that additional meterage drilled and completed added some incremental costs. However, the gains achieved through increased performance have offset these costs by a significant margin.

Additional technical costs are being methodically implemented with resultant further cost reduction. These include an increase to the percentage of multi-well pad locations being executed in the first quarter as compared to 2014.

In addition to this, we continue to optimize our fracture treatment programs most notably in regards to profit selection. Of the most significance has been the reduction in service costs that we realized over the quarter and the progression of these reductions since January has been quite dynamic.

Through January and into February, there was a certain level of hesitation from various service contractors to make significant pricing reductions immediately. As the activity decline continued in the industry, pricing competition increased with full realization of our current pricing structure by about mid March.

As such, the quarter average well cost reported in our Q1 release do not adequately represent the cost structure we are actually seeing today. When looking in a more recent interval say over the past month and half, these reductions are significantly deeper than most previously mentioned.

Excluding those currently in progress, the most 15 wells drilled spans this period of time from the middle of March has an accurate representation of our current cost structure. All of these wells are of the Spirit River category and have average drilling case cost of approximately $2.15 million, but the most recent five of these averaging below $2 million.

This compares to a 2014 average drill cost of $2.66 million and a first quarter 2015 average cost of 2.45. Similarly, the most recent set of well completions have averaged approximately $1.25 million as compared to 2014 of $1.7 million, and the first quarter average of $1.45 million.

Okay. Turning to our Chief Operations Officer, Scott Robinson, our cash costs including royalties are down substantially on a per Mcfe basis year-over-year.

How much of that is attributable to economy of scale and how much to the low commodity price, and are there other independent factors at play?

Yes, Jim. All of the outflows of money related to the production of a unit of products, really the cash costs are really comprised of five components, our field operating cost, gas transportation, royalty, interest and G&A, just to clarify what that cash cost is made up of.

This last quarter really low at $0.89, the combination of those five components out is $0.89. That compares to last year’s range of $0.97 to $1.24 per Mcf.

Really good results on our sales price of 417, $0.89 leads us with a 79% margin. Darren has emphasized the fact that our margins are high and that’s largely from this cost structure that we are achieving.

If we compare quarter-over-quarter that $0.89 cash cost to first quarter of last year was, compares to $1.24 last year. The big differences in this reduction relate to the tightening of our field operating costs, are pretty important part of that, and the reduction in the royalty that we paid this last quarter.

We talked a lot about field operating cost, that’s been a corner store of our operations and I won’t get into too many details on that. But we saw that the field op cost drop quarter one last year to quarter one this year from $0.39 down to $0.32.

This was largely the result of reduction in methanol usage, the volume of methanol, that was a concerted effort to focus on consumption of methanol and we were dealing with a little bit warmer winter this past year. So we benefited from that.

Second component of our operating cost reduction was a decrease in Alberta Power prices, tool prices. They sell in about a half in that curve, depending the two half of our op cost.

So those are the reasons for the reduction in operating cost. Royalties fell from $0.46 quarter one last year to $0.18 per Mcf equivalent this year.

Part of that was due to a slight drop in the volume of royalties that we’re paying as a fraction of our production, but largely that was driven from the pricing effect, the value of those royalties that we are paying out per Mcfe. Our price realizations dropped from the 614 per Mcf down to 343 and parallel to that the value of the royalty dropped as well.

So that’s the details of it. We’re going to do our best to continue to improve that $0.89 downwards.

We want to stay at the top of the industry competition and see if we can dig further into that just similar to what Lee mentioned. He has been able to dig into the capital side of the business.

Okay. Turning to our VP of Land, Tim Louie, have we seen a drop in the cost of land sales given the lower commodity prices and how does the acquisitions being made outside of land sales, are they reflecting a discount due to tough times in the past?

Thanks, Jim. We definitely have seen a decrease in the average price paid at this year’s land sales.

Over the first four months of 2015, the total bonus paid for Alberta Crown petroleum and natural gas rights is down 60%. The average bid price this year is $67 per acre, last year’s average bid price over the same period was $164 per acre.

This lower price environment has provided Peyto with the opportunity to acquire lands at reasonable prices. In the first quarter of 2015, Peyto acquired 14 sections for an average price at $92 per acre.

With regards to other acquisitions outside of land sales, the current price environment has been conducive to getting more deals within our core areas. Companies that are not as active as Peyto seem to be more willing to deal on their acreage.

This is especially true when those companies have expired in lands. This year Peyto has already been able to transact on more swaps, purchases and farm-ins than we did last year.

We are working on more deals; some of this will be finalized within the next month. So while the lower commodity prices are hindering the patch as a whole, for Peyto and it’s inherent low cost structure, it has be provided us with an opportunity to acquire a land both at land sales and through tuck-in acquisitions at very favorable metrics.

Okay. Turning to our CFO, Kathy Turgeon, as the cash cost of debt drops on a per Mcfe basis.

It seems to be dropping faster than the increase in reduction volumes and the increase of net debt for us. How much improvement are we seeing in the actual cost of our capital?

Thanks, Jim. The cash cost of debt have dropped from $0.23 per Mcfe in Q1 of 2014 to $0.20 per Mcfe in Q1 of 2015.

Our average interest rate was reduced from 4.3% in Q1, 2014 to 3.6% in Q1, 2015. The underlying interest rate has not changed significantly but in April of 2014, Peyto negotiated a new credit facility that had decreased stamping and standby fees charged on our credit line.

In addition, Peyto has moved to a lower debt to EBITDA range in the credit facility pricing grid, which gives us a – an increased cost per debt. The combination of these two factors is behind the reduction in our debt cost and given the current environments in the debt markets, the assumption that it continues, but you will see these low cost continued.

Okay, thank you. JP, with the lower cost per well and greater well lengths, but taking into account the lower commodity prices, how the economics with the various well types in our pallet of drilling opportunities being impacted?

Okay. Turning to Dave Thomas, our VP of Exploration, we note that we purchase some several hundred square kilometers of 3D seismic data in the first quarter.

Can you explain how this impacts our inventory of drilling plans for the remainder of 2015?

Jim, we knew 3D seismic was acquired to support drilling. I think the two new facility expansions and to also help select the best places to test a couple of new land blocks.

After breakup in the Ansell/Edson area, we planed to have two or three of our 10 drilling rigs drilling Wilrich and Middle [indiscernible] Horizontals to supply our Swanson gas plant, where we have looped the pipeline and are also adding 40 million Mcf per day of new plant capacity. This will bring the total capacity at Swanson up to 105 million cubic feet per day.

Down at Brazeau, there will be two rigs drilling to follow-up on some strong Wilrich results there in this winter. 10 million cubic feet of new capacity will be added in Q3 at the Brazeau plant to bring its total capacity up to 50 million cubic feet per day.

First, we are looking at a further expansion in Q4 or in early 2016. The two new areas we want to test are in Minehead, south of Ansell and an area we call of West Wildhay.

At Minehead we plan to test the Wilrich in Q3, at West Wildhay we would like to test the Notikewin in Q4. Our other five rigs will be deployed in the Greater Sundance area where we – where our 3D coverage is already quite excellent.

These rigs will be drilling in mix of Wilrich, Notikewin, Blue Sky [ph] plus upper and middle Fahler targets.

Okay. Thank you.

Lee, how are our operations progressing in breakup so far this year, is the breakup season different from last year’s, is there activity in breakup different from last year?

Jim, for the last couple of years, we sometimes ask ourselves that breakup is here, as discussed in our year end conference call, we were in the midst of negotiation with industry road owners in the Greater Sundance area. With the goal in mind to maintain an active spring breakup capital programs should we see favorable condition.

As we experienced in 2014, operating conditions to-date this spring have been remarkable. Although access restrictions were initiated by the various road owners though late March and into early April, these favorable conditions and our successful negotiation have resulted in our ability to maintain continuous operations on six drilling rigs and two to three completion spreads.

The remaining Peyto contracted rigs and associated completion gear to support those rigs are situated outside of Greater Sundance area, where breakup access agreements we are not accomplished. We await listing of road band restrictions which we anticipate to occur late in May or early June.

And as illustrated by the prior discussion on our cost structure, we have again proven through the concept of community of people and equipment results in extremely high level of sustained performance and capital efficiency. Our gross well count exceeding breakup this year is expected to be very similar to the gross well counts we reported exiting breakup last year.

And this breakup program has allowed us to load-level our organization. And as stated in the past, we get to accomplish more with less.

Okay. Darren, when we spoke about the – our capital budget for 2015 in the last conference call, you presented a plan to keep the activity level as planned in the fall, but expected to reduce costs bringing the capital budget down, are we own track with this, have the commodity price gyrations since mid-March made for any changes to our plans?

Yes. Jim, I mean as Lee is talking about we are I think exactly on track, in fact maybe a little bit ahead.

Really I think last year we drilled right through breakup, but I don’t think we are able to do as much completion work as we are accomplishing this year. So, if anything – I think we are a little bit ahead.

So, yes, right from the start we had a big aggressive plan in mind for this year. We wanted to take advantage of we thought – what we thought were going to be dropping service costs.

We had record number of wells that we wanted to drill and we are still on that exactly on track. We are realizing and have realized the cost savings that we needed to realize the economics to still work as JP talked about.

We have got those in hand. We are continuing to improve upon those as Lee was talking about.

I think it bodes very well for us having a very aggressive year and may be even considering more activity than we have originally planned here depending on how the year pans out and of course depending on what kind of royalty regime we are going to be experiencing perhaps next year. But the current environment is very good.

And yes, we got some commodity price gyrations, but that really is what’s driving opportunity for us, the lower oil prices, the questionable gas, prices in people’s mind is what’s shutting down a lot activity in the province and that’s where we come alive. We are able to make still very good returns on the capital we are investing.

We have very good achievements in both sides of the cost structure. So, yes we are excited of about this year.

I think that the plan is as always it’s fluid. It reacts to changing commodities and the changes that we see going forward, but the foundation of our strategy is solid as ever.

Okay, thank you. Wayne, I would like to turn the call over at this point in time to questions from investors and representatives of investment businesses.

Hi, it’s Fai here. I just want to understand this in terms of acquiring land from other producers that may not be able to make it work at this, given the low prices, saying the suggestion that’s economic for you because of your lower cost structure.

Can you maybe comment on the factors behind that? Is it because some of those lines close to some of your existing infrastructure or is it close to some of your rigs or do you have better service contracts?

I am just trying to understand what your advantage there is in terms of why you will able to make some of this property work versus someone else? Thanks.

Yes, I mean, it’s all those things really. I mean, we have got a very significant stronghold in terms of infrastructure out in our core deep basin areas.

All of our gas plants and pipeline infrastructure create fairly significant barriers to other parties to come in and develop resources, whether they acquired those lands recently or have had them for a long time. And just the general activity levels in the industry are pretty low and on gas have been pretty low.

So, there is a lot of minerals that are still continuing to expire that guys have had for 5 years, they maybe brought them 5 years ago thinking gas prices will be better or commodity prices will be better. And of course, they haven’t drilled them to this point.

So, lot of it is expiries. We have highlighted that in the past calls and in our presentation over the expiring lands that are coming down the pipe.

And a lot of it too I think has to do with limited capital programs. Companies have to allocate capital to perhaps to core areas.

And these lands may not be that for them, so that creates an opportunity for us. And ultimately at the end of the day, as you mentioned, we do have an extremely low cost structure.

So, we can in certain opportunities carry a little bit of a burden. We can farm in and offer a gross overriding royalty to that mineral owner in order to develop those resources and still that well is profitable, because we have an advantage cost structure.

So, I think all of those reasons really contribute to why we tend to be the perhaps the company of choice for guys to look to, to either farm out their lands or deal those lands away. And then as we mentioned in the press release too, we have got a fairly sizable war chest now of available capital that we can use to make purchases.

And we have seen this quarter especially debt levels for a lot of producers climbing quite aggressively. A lot of guys are going to have to do something about those debt levels, so that means selling off non-core lands and properties and we are definitely in a buyers market, there is no question.

So, I am glad to see that there is capitulation by the sellers and that we can get the deals done. That’s good.

Alright, great. Thank you.

You bet.

Hey, good morning guys. Just want to you guys alluded to the new fiscal regime a couple of times in your prepared remarks, but just wanted to get some more color there.

I know it’s obviously very early days, but what impact might this have on your business and I guess what potential changes are you most afraid of?

Well, Kevin, as you know we are 100% Alberta. That’s been our strategy right from day one.

We believe in the resources in Alberta and we believe the governments in Alberta want those resources developed. And we all remember the Our Fair Share disaster that happened I guess in 2007, where the government came out with a new royalty regime that wasn’t particularly well thought out.

And it didn’t last very long. They have to obviously respond to activity levels in the industry with a whole bunch of incentives in patches in order to, I guess bring it back into a form that works for both parties, but nothing has changed today.

She has commented that she wants the fiscal regime in Alberta to be competitive. She said that she wants it to be fair.

And she also doesn’t want to scare away activity. And I think even yesterday the fact that she came out after the market closed and had a press release, tried to reassure everyone that, that was going to be her goal, really does tell me that she is going to use the market as a barometer for her policy, which is great.

I think the Stelmach government arguably I think wasn’t thinking that way and we are shocked to see what the market did and this government is already looking quite closely at what the market responds to their policy might be. So, at the end of the day, what we do know is that Peyto is solely it’s so efficient, it’s so environmentally friendly, and it’s so profitable that arguably we should be the poster child for any type of company that the Alberta government wants to operating in Alberta and developing Alberta’s resources.

Because we are so efficient, there will always be more real return to be shared by the people of Alberta as the royalty owners and for our shareholders than can be generated by really any other operator in the industry. So, for me as a lifelong Albertan, I want to incentivize companies like Peyto.

I want them to invest in Alberta. I want them to employ Alberta.

And I want them to profitably develop Alberta’s resources. That’s good for me as an Albertan.

And I think ultimately that’s what this new government wants to. So, I don’t think we need to be particularly fearful of what they are thinking.

Right, well said. On the – you guys benefit quite a bit from the natural gas detailing royalty program.

Do you think you could quantify the financial benefit from that program that you are realizing today and if that was – is that drilling credit were changed or eliminated how might that impact your activity levels?

We do benefit from that program for sure. That helps the economics, but you have to remember too that maybe comparing our economics within the health of program is not the right way to look at it, because again we are one of the most efficient companies out there or most profitable companies out there.

We need to compare it to the average company in the industry that we want to encourage drilling from and how does it affect their economics. And I think what we find obviously is that today’s commodity prices that incentive isn’t good enough.

We need more incentives to get capital invested in the province to get drilling happening for natural gas in the province at today’s commodity prices, because we have the incentive today and drilling activity is shutting down. So, that’s the reality on both oil and the gas side is that if we are going to talk about revising the fiscal regimes and looking at the incentive programs we are drilling today, we probably need to make them even better, because we need to incent capital to come into this industry, so that we can be competitive in North America at these commodity prices.

Not make them worse, make them better. But if you think back to all the different physical regimes Alberta has had and all the different types of incentives that have come in and gone over time, I think we have evolved.

We have a sophisticated royalty restructure right now that works. It does incentivize the right type of drilling.

We are getting out the right types of resources. And arguably, we are competitive in North America.

There has been a lot of analysis that show that over the last sort of while. So, I think it’s working.

Can it be tweaked? Can we make it even better?

Probably. So, I would say, this government should be looking at that.

Alright, I appreciate the color. Thanks.

You bet.

Thanks very much. I was just looking you could repeat something I just missed some of the details.

If you could just again say, how much a firm versus interruptible service you currently have and you mentioned that you were adding some more firm later this year?

That’s right Barb. And some of this data actually was in monthly report last month too.

But Todd you have had quoted some numbers.

Yes. So we have 10,000 barrels a day equivalent firm coming on in June.

We just brought some on in April. And in November we have got 3,800 barrels a day equivalent coming on.

We are running under current TCPL curtailment, our firm plus 20%, the interruptible that we had available in December of last year when the curtailment came on.

But our firm is running in the 80 – just under 80,000 barrel a day range and it’s going to step up progressively over the year here. So with any kind of interruptible added on to that which is very likely we should be in reasonable shape to produce that capacity as we moved into and beyond summer.

Yes, Todd was mentioning the expectation is typically in summer what happens is there is less flow of gas as gas gets injected into storage. The pipe is arguably less full and so there is more room for interruptible service capacity.

So plus the firm that we are adding should be more than sufficient to cover off on our production capability. But you know Barbara this is one of the comments I made in my monthly report is you have to be a little bit careful with respect to transportation.

And I think we have seen this quarter with a lot of companies that their transportation costs have significantly increased because they are carrying unutilized firm service or firm transportation or takeaway capacity and those costs can really start to add up. They can really start to grind away on your profitability.

And yes, you might be able to produce, but if you are producing for no return what’s the point. So we have to be a little bit careful with respect to matching perfectly the production capability of the company with firm take or pay type transportation agreement.

Yes. I was going to just ask you about that sort of with the expected volume growth out of the area, how are you going to balance I guess your – the strategy I guess for meeting your growth volumes and looking at firm versus interruptible while managing the costs, do you have a specific strategy in terms of how much firm you want?

Well, historically we have run with about 90% firm at any given time and that’s a very high number historically for the industry as well and arguably we can do that because we control all of our production, right. We operate all of it, we produce it all through own facilities.

There is no risk that somebody is going to shut us in. And we have a lot of confidence in our production capability.

We have very low risk production. The wells are going to water out and surprise us down the road.

So all those reasons we can commit to a greater percentage of firm than most industry participants can. And we have been adding layers of firm service as we have added production and are confident that our production is good and here to stay and we are going to build upon it.

But we have to be again a little careful because we like to be counter cyclical to the industry. If tomorrow gas prices were to go to $6 an Mcf and the industry goes crazy drilling gas wells and we decide we don’t want to participate in that overheated environment, then our growth is going to slow.

And so as a result we don’t want to be caught with the whole bunch of extra firm capacity. So you are right, it’s a delicate balance, but it is easier for us to do.

No question because we operate all of our production. We operate all of our capital projects.

We know exactly when and how much we are going to be bringing on and how we are going to be drilling. We are not handling the keys, like many operators do, over to other parties to do the drilling, to bring on new production.

And so then we are at their mercy of whatever their timeline is and we don’t really know and how do we pair that with firm service. We don’t have any of those risks.

So, we are in a much better position to properly match exactly what our production volumes are going to be with how much service we need.

That’s great. Thanks so much.

You bet. Thanks for your questions, Barbara.

It’s good.

Okay. Well, thanks for listening in.

Again, this is a busy week. So, appreciate everybody’s participation and we are going to be back to you in August with second quarter, which is setting up to be another very good one for Peyto in terms of activity levels and hopefully the results continue to come in and generate the returns we are looking for.

So, until then, keep an eye on our website for monthly updates and we will be back to you in August. Thanks, again.