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Enerplus Corporation (NYSE:ERF)

Q1 2013 Earnings Call

May 10, 2013 10:30 am ET

Executives

Jo-Anne M. Caza – Vice President-Corporate and Investor Relations

Gordon J. Kerr – President and Chief Executive Officer

Ian C. Dundas – Executive Vice-President and Chief Operating Officer

Ray J. Daniels – Senior Vice President-Operations

Eric Le Dain – Senior Vice President of Strategic Planning, Reserves & Marketing

Analysts

Greg Pardy – RBC Capital Markets

Cristina Lopez – Macquarie Capital Markets

Kyle Preston – National Bank Financial

Roger Serin – TD Newcrest

Patrick Bryden – Scotia Bank

Dirk Lever – AltaCorp Capital

Grant Hofer – Barclays Capital

Operator

Good morning my name is Sara and I’ll 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.

Jo-Anne M. Caza

Thank you, operator, and good morning, everyone. Thanks for calling in. So this morning, Gord Kerr, our President and CEO, will start this off. Then he will 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 in Ian’s succession 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 & 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 were 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’ll 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.

Gordon J. Kerr

.

Well, thanks Jo-Anne and good morning everyone. Thanks for joining us on this 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 of 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 shown discipline in our capital spending, we are seeing cost reductions in key areas. And our financial position remains strong and 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 President and CEO. Now I’ve been with Enerplus and in 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. In fact transitioned our entire company with the goal of building profitable growth and improved sustainability and we’re well along the strategic task, as evidenced by the results again this quarter.

I have confident that Ian, our executive team, and our staff will continue to build value for our shareholders. I’m 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.

Ian C. Dundas

Thanks, Gord. Good morning everyone. 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 over the Marcellus where we saw production grow by about 40% from the fourth quarter. The Marcellus now represents close to a third of our corporate gas volumes. Our capital spending is also on track with our full year plan. We spent $173 million during the quarter at about 25% of our full-year budget of $685 million, a bit less than we would have expected largely due to cost improvements in the Bakken at this point.

Funds flow was also $173 million, in line with analyst expectations driven by increased production, strengthening natural gas prices, as well as a strong hedge position on oil. Our operating cost are tracking while G&A cost was 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 and 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 site 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 has hedged about 25% of our gas production for next year. We also have 15% of our crude oil hedged for next year and we will 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 continues to be the major area of spend for us. We saw an increase in production again this quarter by about 4%, now there is 14,600 BOE a day during the quarter, a new high. The key takeaways 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 of drill complete – long horizontal wells, 9,600-feets with high-strength proppant as the completion have $13 million when we set our budget last fall.

To date, we’re seeing our long horizontal well cost average about 10% under that number. The majority of the savings related to the completion which is about $1.2 million per well lower. Although we are clearly very focused on cost improvement and which I guess expect to see improvement from those numbers, for budgeting purposes or for planning purposes, I guess we’re using a $11.5 million well cost now for the back half of the year.

We’ve seen – often seen some very strong performance from other operators in the area who’re using larger 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 it very carefully and have now tested the 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 spend $15 million in Medicine Hat continuing our field optimization work by drilling five injectors and two producers. We’re also 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 in Medicine Hat continues to perform well. We expect to expand our polymer flood area and are finalizing last details of these expansion plans.

Our Ratcliffe assets in Saskatchewan are another optimizing success story for us. We spend about $11 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’ve seen this light oil project grow from production of 700 BOE a day in 2010 to over 3,500 BOE a day this quarter. Once we move to breakup, 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 $49 million on our natural gas assets in the first quarter. About half of that was spent in the Marcellus and in the Wilrich and 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 last year. We spent $13 million in the Marcellus; it’s a bit under our expectation 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 times.

As the infrastructure build is finally catching up the drilling, we are slowly shipping away at the backlog drilled, but under or not completed wells that existed for much of last year. But there is still backlog of about 14 net wells that are either waiting on completion and/or (inaudible) 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 the 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’re going to start to see 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 $80 million, but we wouldn’t expect this to have any impact on our overall capital guidance.

With NYMEX gas currently over $4 our net back on Marcellus production is now around $2.50 in Mcf. As our production has increased and gas prices improved, our outlook for funds flow on this project has improved dramatically taking the Marcellus much closer to self funding.

Shipping finally to Canadian natural gas, the focus has largely been in the Wilrich where we spent $13 million drilling another two horizontal wells last quarter. We’ve drilled five appraisal wells in this play now from I guess 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 first 30 days.

The second well though is greatly exceeding our type curve it reached peak test rate of 35 million cubic feet a day at a pressure 15.3 MTA over its 17 hour initial test period in mid-March. We brought the well production mid-April, mid-April and it’s been averaging about 17 million cubic feet a day of gas, 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 accept fall of those with the horizontal well 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 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 $58 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 but our plan remains to be strategically opportunistic, but the good news is that we have a very solid track record of making those deals happen.

The proceeds from our divestment activities along with increasing cash flows will give us choices regards to increasing the investments into place like the Wilrich, the Montney or the Duvernay. So let me wrap up my comments before I move on to questions. This is another good quarter for Enerplus and we believe we have met or exceeded analyst expectations. Production volumes were strong, we’re 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. We establish credibility of our investors and close that valuation gap. We believe we are up for the challenge.

And finally on behalf of Board, sorry on behalf of the Board, I will be working – on behalf of the entire organization; I want to thank the Gordon for his vision, guidance, his steady hand and his leadership over the past 12 years sitting at the helm.

And with that, I will turn the call back to the operator and we are available for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Greg Pardy with RBC Capital Markets. Your line is open.

Greg Pardy – RBC Capital Markets

Hi, thanks. Good morning and absolutely all the best to you Gord. Just a couple of questions, I am wondering if you could break down your first quarter U.S. gas production, just want to get a feel for how much of that is coming from the Marcellus what operated versus the non-op. And then also just wanted to get a sense in terms of just gas volumes coming out of the Bakken because I know that’s not a big number but just wanted to understand it better.

And then secondly with respect to your Bakken volumes going to the U.S. Gulf Coast is it still about a third and do you expect to maintain that share because it certainly looks good for realizations in the first quarter. Thanks very much.

Gordon J. Kerr

So, Greg, I will take the first part of the question and then I will hand the second part over to Eric Le Dain. So in terms of the splits, so 79 million a day in the Marcellus and that was virtually all non-operated. We have very little operated activity in just – it rounds to zero the operator piece. The total corporate volumes when you back that out, that was above 15 million a day coming out of the west and then that’s a combination of volumes from Montana and fleet in join assets and North Dakota. I will now turn it to Eric to go over the second part of the question.

Eric G. Le Dain

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

Greg Pardy – RBC Capital Markets

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

Eric G. Le Dain

If that – I think you know the dynamic in the marketplace right now in fact, there’s a good potential there. What happens near-term as we shift more crude back on to the pipeline, differential shift in both on the LLS side and in Clearbrook? So we actually could see in the next month or so a little bit more going back to that kind of Mid-continent Clearbrook area.

Greg Pardy – RBC Capital Markets

Okay, good to know. Thanks very much.

Operator

Your next question comes from the line of Cristina Lopez with Macquarie. Your line is open.

Cristina Lopez – Macquarie Capital Markets

Hi gentlemen and Gord, congratulations on the retirement. With respect to costs in the North Dakota Bakken you’re looking at running about $1.5 million in cost savings, is that would equate to around the $30 million to $35 million mark for savings through the course of the year. What are your intentions for reallocating that capital, or if you are, or you potentially just going to be actually running a budget that might be below what your initial guidance was?

Gordon J. Kerr

We’re very, we’re very focused on meeting our targets Cristina. So we’re sticking with that capital guidance in terms of reallocation within that. I guess there is a chance we could bank that money. But as we look at opportunities in our portfolio, we see some pretty interesting things, we also like to put money into as well. So at this point – and then again we’re talking $680 million budget. So, there is lots of moving pieces within that.

When I look at the Bakken, I don’t see increase pace of activities there. We 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 maybe increasing a little bit, so we talked about that, within Canada. Probably the bigger moving pieces on the operated side with the, some of the earlier stage assets, the Wilrich is an example, the Montney is another example as well and then there is always a little bit of non-op moves around there.

Cristina Lopez – Macquarie Capital Markets

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

Gordon J. Kerr

We’ve talked about drilling two to five wells. From a productivity perspective, we can get those deliverables quite easily just by keeping the two wells we have drilled. If you step back, for us, it is really, really important to demonstrate that we can maintain this financial disciplines and the efficiencies of the program are improving. We can demonstrate that to people.

And so, if you look at the divestment plans as an example, if we’re successful on 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 is an example, absolutely and we are looking at that, but the timing of that is going to depend upon this continued improvement in our funding shortfall.

Cristina Lopez – Macquarie Capital Markets

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

Gordon J. Kerr

No.

Cristina Lopez – Macquarie Capital Markets

(inaudible)

Eric G. Le Dain

Like what’s your name going to be.

Cristina Lopez – Macquarie Capital Markets

Are you looking – are you doing it?

Eric G. Le Dain

Let me answer this way. So we’re not looking for an ex-lawyer, we’re – I think 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 are 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 executive table I have around right now. So give us some time, we’re going to work through that, but I think we’re not panic 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 still sit beside me and he will be here till June and so we got a timetable up here. So stay tuned.

Cristina Lopez – Macquarie Capital Markets

Excellent and congratulations on a great quarter.

Eric G. Le Dain

Thanks.

Operator

Your next question comes from the line of Kyle Preston with National Bank. Your line is open.

Kyle Preston – National Bank Financial

Yeah, thanks. Ian, just wondering if we can just a follow-up question on the Wilrich well. Just 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’s your takeaway and processing capacity is out of that region?

Ian C. Dundas

Yeah, hold on, I’ll turn that to Ray Daniels to talk to, so anything special that happened and then takeaway capacity those kind of things.

Ray J. Daniels

Yeah, I think what we’ve been doing is high-grading the locations that are picking there. And as we continue to look at our program going forward, we will look at the location as we believe we’ll get the best results. And we do see variability through that play, what we have to do is to make sure we understand and continue to understand it through the production that we have and will high-grade it though. One that takeaway capacity and Eric do you know?

Eric G. Le Dain

What is available for takeaway capacity at this point it’s our need, 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 and takeaway.

Gordon J. Kerr

And we’re not limited; we’re going to (inaudible) not limited by production here either. So we don’t see any major constraints on takeaway.

Kyle Preston – National Bank Financial

Okay, thanks a lot guys.

Gordon J. Kerr

The only thing I’d like to add is that, we’re still sticking with our tight curve, so that five or six Bcf areas of variability has seen, but with the five wells we have to date we seem to be averaging a bit ahead of that right now.

Kyle Preston – National Bank Financial

And just four or five wells you have planned for the full-year?

Gordon J. Kerr

We thought two to five is a range and we’ve got two done so far.

Kyle Preston – National Bank Financial

Okay, great, thanks a lot.

Gordon J. Kerr

You are welcome.

Operator

Your next question comes from the line of Roger Serin with TD Securities. Your line is open.

Roger Serin – TD Newcrest

Good morning everybody

Gordon J. Kerr

Hi, Roger.

Ian C. Dundas

Good morning.

Roger Serin – TD Newcrest

So first to Gord, my congratulations. Moving on…

Gordon J. Kerr

You can’t push it to me on that Roger.

Roger Serin – TD Newcrest

Moving on, on the – so most of my questions have been answered, could you touch a little bit on your plans for the Three Forks?

Gordon J. Kerr

Yes, so 25 wells in North Dakota, about a third of those would be Three Forks.

Roger Serin – TD Newcrest

And you’re going to – can you commingle or just targeting the Three Forks?

Gordon J. Kerr

We land those wells, you decide where you’re going to land them and then what we talked – the separation is only about 30 feet between the Bakken and Three Forks, so we see the excess part into them. So there is no concept of commingling right now. The ultimate development question is one that – if you don’t feel comfortably drilling the Bakken, you are probably drilling the Bakken well and you could got the two separate well going on there, you need frac obviously.

Roger Serin – TD Newcrest

Okay. And some in the area talked about well cost may be $10 million or less, little bit less than what you’ve got today. Are we talking apples-to-apples in terms of comparison? Do you think well length…

Gordon J. Kerr

No, no, we don’t 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 that pressure and they are also not talking about with 100% ceramic. So we could take that and we believe they are also not talking about as completely as we are talking about it. So this is an outride well and has every number that we can think about. This shows up over the first six months of a well life. So I don’t think they are apples-to-apples at all. Yeah, I don’t think they are. So 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 cost 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 look so 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 as profitability. And here 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, so we get a switch to white sand and save ourselves to $1.5 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 – about your G wells and I don’t typically want (inaudible), we take a look at on the promise it had down there and it’s very interesting. We would have thought, you would start to see crushing quite early and the modeling curve you see it within 90 days and they were at wells that are six months out that are. They look like they are above – meaningfully above the high-end of our or high-end curve.

Roger Serin – TD Newcrest

Great, thanks very much for your time.

Operator

Your next question comes from the line of Patrick Bryden with Scotia Bank. Your line is open.

Patrick Bryden – Scotia Bank

Good morning everyone, 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.

Gordon J. Kerr

Thank you

Patrick Bryden – Scotia Bank

And then I do have a question just curious to maybe you 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 Marcellus and the Bakken and in terms of where we are going in terms of oil versus gas? Thanks.

Gordon J. Kerr

It’s a good question. So we have four focus areas right now. Bakken and Marcellus in U.S. which represent 40% of our production now from close to a standing start. We see capital continuing to be allocated there and a similarish kind of pace. And of critical importance to the company, we’ve been in a relatively significant of spend dynamic down there for the last two years. You can create a self funding quarter this year, that’s possible. I mean it is really closed. It’s very, very different than it has been before.

Canada water floods, EOR continue to be free cash flow generators with a bit of growth and whether they are spinning off $150 million or $50 million depends a bit on pricing and how much growth we are doubling up. So this made this split out of that. And so then the wildcard and the one 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, I mean that is the development rig 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 large extent. We really have five wells into it but you combine that with some other operators you are doing out there and we’re feeling really good that you got a big meaningful project there. The ones that are little more complicated will be the Montney and the Duvernay because when you add them all up, and you look at the timetable, you run out of it far too quickly and there is a lot of risk particularly in the Duvernay at this stage, it’s encouraging results, lot of risk.

And so we started talking publicly almost a year ago above 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 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, sell downs and everyone is out there trying to do and we don’t have – we have not put a gun to our head and so that gives us a lot flexibility and the timing for those things. But some – one or two of those assets will need to be sold down at some point to JV.

Now the only thing, I would tell you that is a complication to that, we still want to focus a portfolio and we have a relatively large deal in non-core assets deal, we haven’t been funding for quite a few years. So those plans can move around a little bit as we’re – if we’re more successful selling some of those non-core assets. And that can influence a timing of that.

You also asked about gas versus oil splits over time. Yeah, I think we made pretty dramatic change from land, we would have been two-thirds no margin gas, two to three, three years ago and now we are 50% oil and liquids and almost all of that oil and it’s two-thirds light oil.

So that’s been a pretty dramatic shift, which was you had to make that happened based on our 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 but disproportionate growth because the economics of the Marcellus are pretty powerful right now, the Wilrich is pretty powerful.

And even the Duvernay, we decided with the Duvernay coal in there and even if you get the high-end of liquids gas, you still bring oil gas on, so I think we’re going to see more balance, we’re going to see growth, but we’re going to see more balance growth in terms of the commodities on a go forward basis.

Patrick Bryden – Scotia Bank

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

Gordon J. Kerr

Thanks Patrick.

Operator

Your next question comes from the line of Dirk Lever with AltaCorp Capital. Your line is open.

Dirk Lever – AltaCorp Capital

Thank you very much and Gord, all the best to you as you working your yard and enjoy your future. I can tell you there is moose running through your yard. I saw one yesterday. My question is going to focus on the Marcellus. You’ve got corporate gas coming out of there as great party yards and most of it’s 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’re giving as far as production goes, we just want to believe it wildly profitable yet. It seems constrained by infrastructure and the pace of development by your partners.

Gordon J. Kerr

When we have, when we got into this, we thought we’re going to deal, and so, what we’re talking about northeast Pennsylvania now. I mean that is, where our development is focused and that’s where you have seen this unbelievable performance.

We initially thought we’re dealing with maybe four to five Bcf wells and now you got counties that look like they might average, they might average 10 and you got wells between 25 Bcf. If we’re thinking about a well, that’s 5 Bcf, we have gone non-consent because the economics 5 Bcf wells that carries it. And so it’s been dramatical performance and has stressed the whole system from an infrastructure perspective, and we always knew this infrastructure had to build out, but it’s structured in trunk lines and all of that.

And so the infrastructures limitations have impacted the pace of production growth last year, but what also impacted it were operators, almost every operator and there is 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 cost not fall, and cost is not going to be down as well. And so we look at our operators and the pace we build last year has much impacted by them slowing capital as it was by infrastructure. So infrastructure made them very significant progress towards the back half of the year and then that freed up a lot of gas and then you are seeing it in the North American gas volumes in the Marcellus specifically.

So I look at where we are now, and we’ve broken it back on lot of the infrastructure challenges at least for the next piece of growth, and we are 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 is a whole math of level infrastructure expansion that’s going to have to come with that.

Relative to alignment with our operators and the non-operators in nature of it, it’s been okay. There is a few things are, you guys 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’re going to lose this incredible opportunity and so it was tough call we made strategically last year in some respects but it really seems to paying off right now.

Eric G. Le Dain

I think the only addition to that might be the least saving relative to last year and the gathering systems and catching up next.

Dirk Lever – AltaCorp Capital

Yes.

Eric G. Le Dain

We are seeing the benefit of that.

Dirk Lever – AltaCorp Capital

Yes, absolutely. Thank you.

Operator

(Operator Instructions) Your next question comes from the line of Grant Hofer with Barclays. Your line is open.

Grant Hofer – Barclays Capital

Good morning guys. Hi Gord, obviously congratulations, likewise if everyone else. It’s obviously been a great run. Guys I was curious if you could comment on current production volumes and what you’ve budgeted in terms of the impact of breakup here in Canada?

Gordon J. Kerr

Breakup is a bit hard to call and so we have got a reasonably wide range of variability as to what could happen with the breakup. I think we will be – we will have less exposure than others might when you look at the specifics of where our projects are and particularly North Dakota. But a big breakup could affect all of us and so there is obviously contingency built into that. We are probably running a little bit ahead of where we were in the quarter and so feel pretty good about volumes right now but still early in the year.

Grant Hofer – Barclays Capital

Okay, thanks for that. As well those Wilrich wells, what is the well cost on those?

Gordon J. Kerr

We are right now sitting in an $8 million kind of range. When we make the call to go to development, it takes about a million bucks out of that through pads and the like.

Grant Hofer – Barclays Capital

Great, okay. Thanks for that. That’s good for me.

Operator

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

Jo-Anne M. Caza

Okay. Well thanks everyone for participating with us this morning. We will check with you again next quarter.

Operator

This conclude today’s conference call, you may now disconnect.

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