Enerplus Corp (ERF) 2013 Q1 法說會逐字稿

Good morning. My name is Sarah and I will be your conference operator today. At this time, I would like to welcome everyone to the 2013 Enerplus Corporation first-quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Thank you. Jo-Anne Caza, you may begin your conference.

Thank you, operator, and good morning, everyone. Thanks for calling in. So, this morning Gord Kerr, our President and CEO, will start us off. Then he'll be turning the call over to Ian Dundas, Executive Vice President and Chief Operating Officer. As announced in March, Gord will be retiring at the end of June and Ian will succeed him as our new President and CEO. To help answer some of your questions at the end of the call, we also have with us, Rob Waters, our Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Operations; Eric Le Dain, our Senior Vice President of Strategic Planning, Reserves, and Marketing; and Rod Gray, our Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this information, and review our advisory on forward-looking information found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and EDGAR. They are also available on our website at www.enerplus.com.

Our financial statements are also prepared in accordance with International Financial Reporting Standards. All financial figures referenced during the call are in Canadian dollars unless otherwise specified and all conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 energy equivalent conversion ratio, which does not represent the current value equivalent. Following our review, we will open up the phone lines and answer any questions you may have. We'll also have a replay of this call available later today on our website. With that, over to you, Gord.

Well thanks, Jo-Anne, and good morning, everyone. Thanks for joining us on the call today. Ladies and gentlemen, just a few brief opening remarks by me, before I turn it over to Ian. I am pleased to report strong results for the first quarter of 2013. Our assets are delivering profitable, organic growth, building off positive momentum created with our year-end results. And we are tracking ahead of guidance on production, and we expect to achieve our guidance targets on all other measures. We've shown discipline in our capital spending, we are seeing cost reductions in key areas, and our financial position remains strong. The sustainability of our Business has improved substantially.

Now, as announced in March, I will be retiring at the end of June, and in accordance with our succession plan, Ian Dundas will be assuming the role of the President and CEO. Now I've been with Enerplus and its [successive] Companies for over 30 years. And over that time, we have experienced our share of success and challenges. During the past few years, we have been working hard to transition our asset base. And in fact, transition our entire Company, with the goal of building profitable growth and improved sustainability.

We are well along this strategic path as evidenced by our results again this quarter. I have confidence that Ian, our Executive team, and our staff will continue to build value for our shareholders. I am proud of the progress we've made and the team we have assembled at Enerplus. I appreciate not only their support, but that of our shareholders, as well as our Directors, and I appreciate that over the full tenure of my term as President and CEO. So, with that, Ian, over to you.

Well thanks, Gord. Good morning, everyone. As Gord said, we've had a good start to the year. Our production was ahead of analysts' expectations at 87,000 BOE a day, up 2% over the fourth quarter, driven primarily by record production in the Marcellus and at Fort Berthold. The largest increase was out of the Marcellus where we saw production grow by about 40% from the fourth quarter. The Marcellus now represents close to one-third of our corporate gas volumes.

Our capital spending is also on track with our full-year plan. We spent CAD173 million during the quarter. It's about 25% of our full-year budget of CAD685 million, a bit less than we would have expected, largely due to cost improvements in the Bakken at this point. Funds flow was also CAD173 million, in line with analysts' expectations, driven by an increased production, strengthening natural gas prices, as well as a strong hedge position on oil. Our operating costs are tracking, while G&A costs were slightly higher than expected due to one-time charges. We are maintaining our full-year guidance targets for both operating costs and G&A.

As Gord highlighted, the sustainability of our Business has improved significantly since last year. Our adjusted payout ratio was over 250% last year; the combination of higher production, improving capital efficiencies, a lower spending profile, and a lower dividend resulted in a payout of only 126% in the first quarter. We also see the opportunity for additional improvement, as gas prices now come up, and we see line-of-sight to additional cost improvements. Hedging is an important part of the strategy and we have a strong hedge book in place. We have price protection on 64% of our oil and 33% of our gas production after royalties this year. That should provide us with good funds flow production for the remainder of the year.

The majority of our funds flow continues to come from crude oil production, but we have seen an improvement in natural gas prices in recent months. Although we do believe gas has further upside potential, we've taken advantage of the recent price uptick and have hedged about 25% of our gas production for next year. We also have 15% of our crude oil hedged for next year, and we'll look for opportunities to add hedges, particularly on the oil side, for 2014.

Now, let's move on to some operational highlights of the quarter. North Dakota continued to be the major area spend for us. We saw an increase in production again this quarter, by about 4% and averaged 14,600 BOE a day during the quarter, a new high. The key take-aways at Fort Berthold are the production is growing and that we are seeing our costs come down. In our budgets, we had forecast the cost to drill, complete, and tie-in a long horizontal well, 9,600 feet with high-strength proppant as the completion, at about CAD13 million when we set our budget last fall. To date, we're seeing our long horizontal well costs average about 10% under that number. The majority of the savings related to the completion, which is about CAD1.2 million per well lower.

Although we are clearly very focused on cost improvement, and would expect to see improvement from those numbers, for budgeting purposes -- or for planning purposes, we're using CAD11.5 million well costs now for the back half of year. We've also seen some very strong performance from other operators in the area who are using larger [sack] -- fracs using white sand instead of ceramic proppant. For the same cost, we can pump about 2.3 times the amount of sand and increase the number of stages. We've looked at this very carefully and have now tested this different completion on a couple of wells and would plan to do this at least a few more times as we move through the year.

Turning to Canadian crude oil and liquids properties, our production averaged just over 22,000 BOE a day from that part of our portfolio. Pretty much flat to the fourth quarter after adjusting for the Manitoba sale, which closed in December. The majority of our activities were focused at Medicine Hat, and in the Ratcliffe in Saskatchewan. We've spent CAD15 million in Medicine Hat, continuing our field optimization work by drilling five injectors and two producers. We're also starting -- started building a new battery to support future production growth in the field. In the first quarter, production at Medicine Hat averaged about 4,200 BOE a day, about flat to last quarter. The polymer project at Medicine Hat continues to perform well. We expect to expand our polymer flood area and are finalizing the last details of these expansion plans.

Our Ratcliffe assets in Saskatchewan are another optimized and development success story for us. We spent about CAD11 million in this area last quarter, drilling three horizontal production wells in addition to some maintenance and facility work and we're pleased with the results so far. And just to frame this growth for you, we have seen this light oil project grow from production of about 700 BOE a day in 2010 to over 3,500 BOE a day this quarter. Once we move through break-up, we'll continue our drilling plans, we'll run one rig there through the back half of the year, as well as continue to convert some original vertical producers into injection wells to help optimize the floods in this trend.

Moving to natural gas, we spent CAD49 million on our natural gas assets in the first quarter. About 50% of that was spent in the Marcellus and in the Wilrich in Alberta combined. Our total gas production increased by about 5%, driven by record non-operated production in the Marcellus, as I mentioned earlier. We averaged 79 million cubic feet a day in the Marcellus during the quarter, up 40% from fourth quarter of last year. And we spent CAD13 million in the Marcellus. It's a bit under our expectations due to slightly slower activity. However, production was very strong due to a combination of strong well performance and the benefit of some late-year tie-ins.

As the infrastructure build is finally catching up to the drilling, we are slowly chipping away at the backlog of drilled but under or not completed wells that existed for much of last year but there's still a backlog of about 14 net wells that are either waiting on completion and/or tie-in that are slowly being worked through. As I said, we are really pleased with the well performance we're seeing. Just to give you some perspective on this, we currently have 24 gross wells that are producing over 10 million a day with one-third of them that have been producing at this rate for 12 months or more. The majority of these monster wells are in Bradford and Susquehanna Counties, where we have about 15,000 net acres.

With the slowdown in activity through 2012, and with much of the lease retention issues now managed, we expect that we are going to start to see a 10% to 15% improvement in costs in the Marcellus. Although activity levels are slightly behind our estimates to date, a combination of improved costs and higher prices could result in a modest uptick in spending beyond our budgeted CAD80 million, but we wouldn't expect this to have any impact on our overall capital guidance. With NYMEX gas currently over CAD4 an Mcf, our netback on Marcellus production is now around CAD2.50 an Mcf. As our production has increased and gas prices have improved, our outlook for funds flow from this project has improved dramatically, taking the Marcellus much closer to self-funding.

Shifting finally to Canadian natural gas, the focus has largely been in the Wilrich, where we spent CAD13 million drilling another two horizontal wells last quarter. We've drilled about five appraisal wells in this play now from when we began last year and continue to be impressed by the results from these wells. The first well we drilled this year has been producing on type curve at about 6 million cubic feet a day for the first 30 days. The second well, though, is greatly exceeding our type curve. It reached a peak test rate of 35 million cubic feet a day at a pressure of 15.3 MPa over its 17-hour initial test period in mid-March.

We brought the well to production mid-April, and it's been averaging about 17 million cubic feet of gas a day since that time. We're pretty excited here about the opportunity we have in the Wilrich. We have over 50,000 net acres of land, high working interest in this region, and we see over 100 potential future drilling locations. We're planning to drill two vertical Duvernay wells later this year, as well. This is going to help us better understand the liquids content in this project and we expect to follow up those with a horizontal well at probably Q1 2014 as we get to that.

Strategically, we are very committed to continuing to high-grade our portfolio and improving our operational focus. The sale of non-core assets remains a part of that plan. In early April, we sold 600 BOE a day of low working interest oil production in southeast Saskatchewan and Alberta for approximately CAD58 million. We're also currently marketing a package of small non-core properties with about 1,300 BOE a day of oily production. Our goal, corporately, is to try and accelerate the pace of this divestment activity but it is a tough market and there are many companies looking to sell assets, many of whom have issues with their debt. That is not our situation.

The strength of our balance sheet provides us with a lot of flexibility so we're very focused on it, but our plan remains to be strategically opportunistic. The good news is that we have a very solid track record of making those deals happen. The proceeds for our divestment activities, along with increasing cash flows, will give us choices regards to increasing the investment in plays like the Wilrich, the Montney, or the Duvernay. So let me wrap up my comments before we move onto questions. This was another good quarter for Enerplus. We believe we have met or exceeded analyst expectations. Production volumes were strong. We are delivering on our plans for 2013 and we are well-positioned to achieve all our guidance targets for the year. We are being disciplined with our capital spending and are encouraged by cost performance in key areas like Fort Berthold and the Marcellus.

Our sustainability has improved dramatically and we continue to be in a strong financial position. We believe Enerplus shares are deeply undervalued in the marketplace relative to our peers and our job is to continue to deliver results, reestablish credibility with our investors, and close that valuation gap. We believe we are up for the challenge. And finally, on behalf of Gord -- sorry, on behalf of Gord, that would be a weird thing to say (laughter) -- on behalf of the entire Organization, I want to thank Gord for his vision, his guidance, his steady hand and his leadership over the last -- past 12 years sitting at the helm. And with that, I will turn the call back to the operator and we're available for questions.

(Operator Instructions)

Greg Pardy, RBC Capital Markets.

Hello, thanks, good morning, and absolutely all of the best to you, Gord. Just a couple of questions. I'm wondering if you could break down your first-quarter US gas production? Just want to get a feel for how much of that is coming from the Marcellus both operated versus the non-op, and then, also wanted to get a sense in terms of gas volumes coming out of the Bakken because I know that's not a big number but wanted to understand it better? And then secondly, with respect to your Bakken volumes going to the US Gulf Coast, is still about one-third and do you expect to maintain that share because it certainly looks as though it was good for realizations in the first quarter? Thanks very much.

Greg, I'll take the first part of the question and then I'll hand the second part over to Eric Le Dain. So in terms of the splits, 79 million a day in the Marcellus, and that was virtually all non-operated; we have very little operated activity and it rounds to 0, the operated piece. The total corporate volumes when you back out, that puts about 15 million a day coming out of the west and then that's a combination of volumes from Montana and our Sleeping Giant asset and North Dakota. And then I'll turn to Eric over the second part of the question.

Yes, thanks for that.

Of our operated Bakken crude out of our Sleeping Giant and Fort Berthold assets, roughly -- and this is a very round number, 8,000 barrels to 9,000 barrels a day was going to the Gulf Coast in the first quarter.

Okay and is that a number you would see rising proportionally as your volumes grow or--?

You'd know the dynamic in the marketplace right now. In fact there's a good potential that what happens near-term is we shift more crude back onto the pipeline as differentials shift in -- both on the LLS side and at Clearbrook so we actually could see in the next month or so a little bit more going back to that mid-continent Clearbrook area.

Okay, good to know. Thanks very much.

Cristina Lopez, Macquarie.

Hello, gentlemen. And Gord, congratulations on the retirement. With respect to costs in the North Dakota Bakken, you are looking at or running about CAD1.5 million in cost savings. That would equate to around the CAD30 million to CAD35 million mark for savings through the course of the year. What are your intentions for reallocating that capital or is your -- or are you potentially going to be actually running a budget that might be below what your initial guidance was?

We are very focused on meeting our targets, Cristina, so we're -- but we're sticking with that capital guidance. In terms of reallocation within that, there's a chance we could bank that money, but as we look at opportunities in our portfolio, we see some pretty interesting things that we'd also like to put money into as well. So at this point -- and again we're talking a CAD680 million budget so there's lots of moving pieces within that -- when I look at the Bakken, I don't see increased pace of activity there. We've talked about the Marcellus and we have three main non-operating partners down there. I see two of them holding the line on activity, one may be increasing a little bit, so we talked about that. Within Canada, probably the bigger moving pieces on the operated side would be some of the earlier stage assets, the Wilrich is an example, the Montney is another example as well, and then there's always a little bit of non-op that moves around there.

And sorry, I may have missed this, but what are your plans for the Wilrich for the remainder of the year, given the strength in the results you've seen so far?

We've talked about drilling two to five wells. From a productivity perspective, we can hit those deliverables quite easily just by keeping the two wells we've drilled [to date]. We're -- if you step back, for us it is really, really important to demonstrate that we can maintain this financial discipline, that the efficiencies of the program are improving and we can demonstrate that to people. And so you look at the divestment plans, as an example, if we're successful in this activity, that's going to put some money in the bank and that's going to really give us the flexibility to start to reallocate. And so, is there a possibility we could put money into the Wilrich, as an example? Absolutely. And we're looking at. But the timing of that is going to depend upon this continued improvement in our funding shortfall.

And with respect to the search for a Chief Operating Officer, do you have any color around that?

No.

To pull it off? (Laughter).

You're like, what's her name going to be? Those kind of things? (Laughter).

Are you looking -- are you doing a formal search?

Let me answer it this way. So we're not looking for an ex-lawyer. We're -- the vote that the Board made when they put me in charge was a very strong endorsement of the team. And an endorsement that you can see in the operating results in the fourth quarter and you can see them today. So we think we're in a pretty good place and we want to build from that. We're very, very focused on roles and I'm really comfortable with the guys and the gal at the Executive table I have around right now. So give us some time. We're going to work through that. We're not panicked to do something, to put a title up, or I don't feel a dramatic need to shake it up. I want to build from the position we have right now. Gord is still sitting beside me and he will be here until June and so we've got a timetable we're working through here. So stay tuned.

Excellent, and congratulations on a great quarter.

Kyle Preston, National Bank.

Yes, thanks, Ian, just wondering if we can -- a follow-up question on that Wilrich well. Wondering if you can talk to whether or not there was anything special about that particular location? If you saw anything there and whether or not you'll be able to repeat that? And also talk about what your take-away and processing capacity is out of that region?

I will -- I'm going to turn that to Ray Daniels to talk to, so anything special that happens and then take-away, capacity, those kind of things?

Yes, what we've been doing is high-grading the locations that we are picking there. And so as we continue to look at our program going forward, we will look at the locations we believe will get us the best results. And we do see variability through that play. What we have to do is make sure we understand it and continue to understand it through the production that we have and we'll high-grade as we go. On the take-away capacity, Eric, do you know--?

What is available for take-away capacity at this point meets our needs, and we see it doing so for the foreseeable future, assuming we don't grow too quickly but, at this point we see no issues in processing or take-away.

And we're not limited. We're getting into the [handling north plan], we're not limited by a production there either so we don't see any major constraints on take-away.

Okay, thanks a lot for that guys.

Kyle, the only thing I might add is that we're still sticking with our tight curve, that 5 to 6 Bcf area [affects] that variability rate has seen, but with the five wells we have to date, we seem to be averaging a bit ahead of that right now.

And is it four or five wells you had planned for the full year?

We talked about two to five as a range and we have got two done so far.

Okay great, thanks a lot.

Roger Serin, TD Securities.

So, first to Gord, my congratulations said with some envy. (Laughter) Moving on--

Well, you kept pushing me on that, Roger.

I know. Moving on -- on the -- sorry and most of my questions have been answered

Yes, 20 to 25 wells in North Dakota. About one-third of those would be Three Forks.

And are you going to -- can you co-mingle or is it just targeting the Three Forks?

We land those wells -- you decide where you're going to land them and then -- we've talked about this before, the separation is only about 30 feet between the Bakken and Three Forks so we can actually frac into them so there's no concept of co-mingling right now. The ultimate development question is one that is -- if you don't feel comfortable that you're draining the Bakken, you're probably drilling the Bakken well and you've got the two separate wells going on there because you need to frac, obviously.

And some in the area have talked about well costs. Maybe CAD10 million or less. A little bit less than what you've got to, to date. Are we talking apples-to-apples in terms of comparison, do you think, well length, that kind of thing?

We don't -- no, no, we think so, we don't think so at all. So, the average person talking about that isn't talking about it one specific in that area and at that depth and at that pressure, and they're also not talking about it with 100% ceramic. We could take that number -- and we believe they're also not talking about it as completely as we're talking about it, so this is an average well and has every number that we can think about that shows up over the first six months of a well's life. I don't think they're apples-to-apples at all, -- apples-to-apples, yes -- no I don't think they are. So and that's where we are right now. When we look at non-operated activity, which we participate in to a small extent, we see quite consistent well costs and we see far more variability relative to the completion design. We look on the drilling side and we line up pretty well. Our days continue to inch to the good and the big swings are really going to be on what is that design -- and costs are critical and we're very focused on costs but as importantly is profitability.

And, yes, we saw last year we were able to save money at the expense of profitability relative to changing that completion. This new white sand frac we're testing, it's pretty encouraging. We could just switch to white sand and save ourselves CAD1.5 million. We've chosen to switch to white sand and almost triple the amount of sand and so that's going to be really important, potentially, relative to productivity. You look at some of those EOG wells and I don't typically want to talk about EOG in our call but I am. You take a look at some of the problems they've had down there and it's very interesting. We would have thought you'd start to see crushing quite early. The modeling tells you see it within 90 days and they've got wells that are six months out that are -- they look like they're above -- meaningfully above the high end of our high-end curve.

Great, thanks very much for your time.

Patrick Bryden, Scotia Bank.

Gord, just wanted to give you congrats on your 30 years, and best of luck with the next chapter and road ahead. And Ian, congrats on your new role. And then I do have a question. Just curious to understand if you guys can paint a picture for us in terms of -- as we think about the Duvernay, the Montney, and the Wilrich in combination and you look at the strip today and you look at where your balance sheet is over the next three years or so, how would you want us to be thinking about that in terms of capital allocation versus the Marcella, some of the Bakken, and in terms of where you're going in terms of oil versus gas? Thanks.

That's a good question. So we have four focus areas right now. The Bakken and the Marcellus in the US, which represent 40% of our production now from close to a standing start. We see capital continuing to be allocated there at a similar-ish pace. And of critical importance to the Company, we've been in a relatively significant outspend dynamic down there for the last two years. You can create a self-funding quarter this year. It's possible. It's really close -- it's very, very different than it has been before. So you come into Canada, water floods, EOR, continue to be free cash flow generators with a bit of growth and whether they're spinning off CAD150 million or CAD50 million depends a bit upon pricing and how much growth we're dialing up, but there's money that spits out of that.

And so then the wild card, and the one with more variability, is what you've described, which is our Deep Basin portfolio. And you've got three different things going on there as well. So the Wilrich, that is development ready, and we could hammer on it and drive production to a meaningful level, and that will be part of our plan at some point. The timing is now a function of affordability to a large extent. We've only got five wells into it but you combine that with what some other operators are doing out there, and we're feeling really good that you've got a big meaningful project there. The ones that are a little more complicated would be the Montney and the Duvernay because when you add them all up and you look at the timetables, you run out of money far too quickly. And there's a lot of risk, particularly in the Duvernay at this stage. It's encouraging results but it's a lot of risk.

We started talking publicly almost a year ago about the need to bring in a partner and/or sell down those two assets specifically and it was a reflection largely of the scope of these things. Now that we're fortunate that we have really good land tenure in both of those projects so we have a lot of flexibility in that regard. It's a tough market, clearly, and so the pace of JVs, and sell downs. Everyone is out there trying to do it. And we don't have -- we haven't not put a gun to our head and so that gives us a lot of flexibility on the timing for those things. But, one or two of those assets will need to be sold down at some point through JV. Now the only thing I would tell you that is a complication of that, we still want to focus the portfolio and we have a relatively large tail of non-core assets still that we haven't been funding for quite a few years. So those plans can move around a little bit as we are -- if we are more successful at selling some of those non-core assets, and that's going to influence the timing of that.

You also asked what gas versus oil splits over time. We made a pretty dramatic change from -- man, we would've been two-thirds low-margin gas, two to three years ago, and now we're 50% oil and liquids and almost all of that's oil, and it's two-thirds light oil, so that has been a pretty dramatic shift. When I -- which was -- you had to make that happen based on where gas prices were. Now the economics of gas drilling have come up a bit and are becoming more interesting and so when we look at our portfolio, I don't see that disproportionate oil growth, the disproportionate growth, because the economics of the Marcellus are pretty powerful right now, the Wilrich is pretty powerful, and even the Duvernay, if you decide to put the Duvernay call in there, even if you get the high end of the liquids cuts, you are still bringing a lot of gas on, so we are going to see a more balanced -- we are going to see growth, but we are going to see more balanced growth in terms of the commodities on a go-forward basis.

That's great. I appreciate the answer and Gord, again, good luck with the road ahead. Enjoy.

Dirk Lever, AltaCorp Capital.

Thank you very much and, Gord, all the best to you as you work in your yard and enjoy your future. (Laughter). I can tell you there's moose running through your yard. I saw one yesterday. My question is going to focus on the Marcellus. You've got one-third of your corporate gas coming out of there, as Greg Pardy asked, and most of its non-op, and it sounds like it's infrastructure-constrained, which we've known. Maybe you could add a little bit more color on this because some of the numbers that you were giving, as far as production goes, leads one to believe it's wildly profitable, yet it seems constrained by infrastructure and the pace of development by your partners?

When we got into this, we thought we were going to deal -- so we're talking with northeast Pennsylvania now, that is where our development is focused and that's where you've seen this unbelievable performance. We initially thought we were dealing with maybe 4 to 5 Bcf wells and now you've got counties that look like they might average 10 and you've got wells that look like 20-plus Bcf -- if we're thinking about a well that's 5 Bcf, we have gone non-consent because of the economics -- 5 Bcf wells, who cares right now. And so it's been a dramatic up performance and has stressed the whole system from an infrastructure perspective. And we always knew that the infrastructure had to build out but it's stressed it and trunklines are full and all that. And so the infrastructure's limitations have impacted the pace of production growth last year but what also impacted it were operators -- almost every operator, there's a few exceptions -- but almost every operator out there was trying to limit their spend and so when we look -- relative to the gas price falling and costs not fall -- and costs not coming down as well. And so we look at our operators and the pace of build last year was as much impacted by them slowing capital as it was by infrastructure.

So infrastructure, we've made some very significant progress towards the back half of the year and then that freed up a lot of gas. And then you're seeing it in the North American gas volumes in the Marcellus, specifically. I look at where we are now and we've broken the back on a lot of the infrastructure challenges, at least for the next piece of growth. We're focusing -- we've been focusing more modest growth -- if you think about those -- some of the broad calls as to how big the Marcellus could get, 20 Bcf, and some of those incredible numbers, there's a whole massive level of infrastructure expansion that is going to have to come with that. Relative to our alignment with our operators and the non-operated nature of it, it's been okay. There's a few things our operators might have done a little bit different than us but generally speaking it was the same challenges of trying to manage through a very low gas market and a spend that you didn't really want to do but if you didn't, you were going to lose this incredible opportunity and so it was a tough call we made strategically last year in some respects, but it really seems to be paying off right now.

The only addition to that might be that there was a lot of lease-saving wells drilled last year and their gathering systems and trunklines are catching up now and we're seeing the benefit of that.

Yes. Absolutely. Yes.

Thank you.

(Operator Instructions)

Grant Hofer, Barclays.

Good morning, guys. Gord, obviously congratulations. Likewise with everyone else. It's obviously been a great run. Guys, was curious if you could comment on current production volumes and what you've budgeted in terms of the impact of break-up here in Canada?

Break-up is a bit hard to call. And so we've got a reasonably wide range of variability as to what could happen out of break-up. We'll have less exposure than others might when you look at the specifics of where our projects are, and particularly North Dakota, but a big break-up could affect all of us and so there's obviously a contingency built into that. We're probably running a little bit ahead of where we were in the quarter, and so feel pretty good about volumes right now but it's still early in the year.

Okay. Thanks for that. As well, those Wilrich wells, what's the well cost on those?

We're right now sitting in a CAD8 million range. When we make the call to go to development it takes about CAD1 million out of that through pads and the like.

Great, okay thanks for that, that's good for me.

And there are no further questions over the phone at this time. I turn the call back over to the presenters.

Great. Well, thank you everyone for participating with us this morning. We will check with you again next quarter.

This concludes today's conference call, you may now disconnect.