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Encana Corporation (NYSE:ECA)

Q4 2013 Earnings Conference Call

February 13, 2014 9:00 a.m. ET

Executives

Ryder McRitchie – VP of IR & Corporate Communications

Doug Suttles – President & CEO

Sherri Brillon – EVP & CFO

Michael McAllister – COO

Analysts

Greg Pardy – RBC Capital Markets

Matthew Portillo – TPH

Brian Singer – Goldman Sachs

Bob Brackett – Bernstein Research

Michael Dunn – FirstEnergy Capital

John Herrlin – Societe Generale

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Fourth Quarter and Year-End Results 2013 Conference Call. As a reminder, today's call is being recorded. (Operator Instructions) For members of the media attending in a listen-only mode today, you may quote statements made by any of the Encana representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Encana Corporation.

I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations and Communications. Please go ahead, Mr. McRitchie.

Ryder McRitchie

Thank you, Laura, and welcome everyone to our fourth quarter and year end results conference call. This call is being webcast and slides are available on our website in encana.com if you like to print them.

Before we get started, I must refer you to the advisory regarding forward-looking statements contained in the news release and at the end of the webcast slides, as well as the advisory on Page 39 of Encana's Annual Information Form dated February 21, 2013, the latter of which is available on SEDAR. In particular, I would like to draw your attention to the material factors and assumptions in those advisories.

Encana reports its financial results in U.S. dollars. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S. dollars and after royalties, unless otherwise noted.

This morning, Doug Suttles, Encana's President and CEO will update you on our operations and the progress we’ve made in implementing our strategy that we announced in early November. Sherri Brillon, our CFO will then discuss Encana’s fourth quarter and full year 2013 financial performance. Following the slide presentation, we will have time for Q&A.

I will now turn the call over to Doug Suttles, Encana's President and CEO.

Doug Suttles

Thanks, Ryder and thanks everyone for joining us this morning. We exited 2013 on a strong note and from where I sit this morning here in Calgary, I think we’re off to a very good start in 2014, which is reconfirming our view that our focus on value and not just volumes, is the right thing for Encana.

Back in December, we announced our 2014 guidance. This is off the back of announcing our strategy in November. We also introduced a scorecard, which we intended to report back on as we go through the implementation of our strategy. I am pleased to report that we've already remained [ph] significant progress in putting our strategic initiatives to work.

The fourth quarter of 2013 was both busy and in my view transformational for Encana. In the quarter we launched our strategy in early November. We completed a significant restructuring that will deliver material cost savings and is aligned with our strategy. And we put in place our 2014 budget and plan consistent with that strategy, including a capital budget aligned with our expected cash flow and dividend.

Before Sherri walks you through some of the details of the quarter, I’d like to highlight a few things. First of all, we met our full-year production and cash flow targets while spending $400 million less capital than originally planned. Our balance sheet is in great shape. We ended 2013 with approximately $2.6 billion of cash and cash equivalents on the balance sheet.

Liquids production averaged 66,000 barrels a day in the quarter, which is up 82% year on year versus the fourth quarter of 2012. And financially, the fourth quarter was very good as demonstrated by our very strong cash flow driven by operating performance -- clearly a very strong pricing environment at the end of the quarter and it also included reaching full production rate at our Deep Panuke facility offshore Nova Scotia.

This morning, with the results, we also announced our reserves and resources as of the end of the year 2012. Our reserves are now aligned with our strategy to focus our capital on our 5 growth plays. Thus we’ve reduced our previously planned capital on the PUDs, the proved undeveloped resources outside of the four core growth plays by approximately $4 billion.

The gas associated with our PUD revisions has not disappeared; it's rather -- it's been recategorized. If you sum our 2P reserves and 2C resources that are outlined in today's press release, you will see that the size of our economic reserves and resources is essentially unchanged from a year ago.

I will now turn the call over to Sherri who will provide additional information and detail on our financial and operating results for the quarter and for the year.

Sherri Brillon

Thanks, Doug and good morning everyone. As Doug mentioned, financially we had a strong end to the year with both fourth quarter operating earnings per share and cash flow per share readily beating consensus forecast. This was driven in part by our bail [ph] in oil production in Western Canada that improved the value of our production mix and by Deep Panuke production reaching production capacity with the gas being sold into a premium Northeast U.S. gas market.

While the majority of our natural gas production is sold on a monthly index basis, production from Deep Panuke is sold into the local daily spot market. Cold temperatures in that part of the continent during December certainly helped pricing.

During the fourth quarter, Encana generated cash flow of $677 million or $0.91 per share. Fourth quarter results included $25 million or $0.03 per share recovery in cash taxes and also reflected $64 million after tax or $0.09 per share restructuring charge related to implementing our new corporate strategy. Operating earnings totaled $226 million or $0.31 per share.

Natural gas production in the fourth quarter averaged about 2.7 billion cubic feet per day. Reflecting our focus of growing value and not just volumes, oil production increased from 27,000 barrels per day in the third quarter to about 33,000 barrels in the fourth quarter. While natural gas liquids production increased from 31,000 barrels per day to about 33,000 barrels per day from Q3 to Q4.

We did experience some weather related impacts on our operations in the fourth quarter in the range of about 2300 barrels per day companywide for the month of December. Our full-year 2013 results met or exceeded our guidance targets. Importantly we spent roughly $400 million less than originally planned in 2013 and still met our production guidance and exceeded our cash flow projections.

Encana recorded full year cash flow of approximately $2.6 billion or $3.50 per share, exceeding our guidance range of $2.4 billion to $2.5 billion. Average natural gas production for the year was about 2.8 billion cubic feet per day and liquids production averaged about 54,000 barrels per day, composed of approximately 26,000 barrels per day of oil and approximately 28,000 barrels per day of NGLs.

Our full-year capital outlay came in at about $2.7 billion versus our original 2013 guidance of $3 billion to $3.2 billion. The decrease in capital of roughly $400 million was a result of focusing our spend on our best opportunities as well as achieving efficiency improvements across many of our drilling programs. In particular, in 2013 we experienced significant economies of scale, process improvements and efficiency gains associated with drilling and completions. For example, in the DJ Basin from July to November of last year, we achieved a 34% cost reduction in hydraulic fracturing from moving to floodwater completion fluids [ph] and using the zipper frac technique, which allows us to fracture two wells simultaneously.

In addition, we continue to see significant cost reductions in our Duvernay well cost. On our two most recent completion operations conducted in November 2013, we saw reductions of over $1.5 million per well. These reductions were realized due to increased cost efficiencies associated with continuous operations on multi-well pads and reduced water handling costs. Mike McAllister can speak more to the specifics of operational efficiencies we realized during the Q&A session.

While our transportation and processing costs on a per-unit basis came in above guidance due to slightly lower production. In total, our dollar costs were lower than budgeted. Excluding restructuring costs and LTI, our per unit administrative expense totaled $0.29 per Mcfe, better than our $0.30 per Mcfe guidance on a like-for-like basis.

In 2014, we expect our administrative expense to average $0.25 per Mcfe, excluding LTI and restructuring charges, a significant decrease as a result of streamlining our workforce to align with our new strategy and focused operation activities.

Maintaining a strong balance sheet and investment-grade credit rating, our foundational aspects of our new strategy, we've aligned our 2014 capital spending plans and our dividend with our expected cash flow that's reinforcing the sustainability of our business plan. Further strengthening of our financial position, we ended the year with about $2.6 billion in cash and cash equivalents. This was after we repaid in the fourth quarter a $500 million 4.75% note maturity from cash. We also expect to repay our main 2014 $1 billion 5.8% note maturity from cash as well.

In addition to our cash position, we have about $4.3 billion of unused revolving bank credit facilities committed in 2018, so we have tremendous financial flexibility. Our fundamentals team continuously monitor [ph] local and regional markets and will hedge your production to minimize the volatility of our cash flow. As at year end, we had about 2.1 billion cubic feet per day of our expected 2014 natural gas production hedged at an average price of $4.17 per Mcf. Our hedges for 2015 remain unchanged. We will continue to update you on our hedging activity each quarter as the year progresses.

I will now turn the call back to Doug.

Doug Suttles

Thanks, Sherri. We launched our strategy back in November, and as a reminder, we're focused on growing shareholder value with a particular emphasis on achieving greater balance between liquids and gas production -- a very disciplined approach and focus to capital allocation and by driving industry-leading efficiencies in both our core growth areas and across our large operating base.

When we laid our strategy in November, we also laid out a scorecard focused on three areas. The first of which was portfolio transition. There we said we were going to transition our asset base to focused and disciplined capital allocation.

We also said that we expect to deliver something greater than 10% compound annual growth rate on cash flow per share through 2017 and I should remind you that was at a $4 gas price and a $90 oil price. By 2017 we hope to achieve 75% of our upstream operating cash flow from liquids assuming those prices.

The second area of our scorecard was focused on operational excellence. We reset our cost structures that are now aligned with our strategy. We will focus on higher netbacks and margins through both capital allocation and through ever-increasing emphasis on efficiency.

And lastly, we talked about balance sheet strength. We have a strategy and a business model that is not dependent on asset sales. Our capital program and dividends are aligned with -- largely aligned with our cash flow and we intend to maintain our investment-grade credit rating. We also are working very hard to make sure that our market fundamentals are forming [ph] our capital allocation decisions and also help us secure our short-term cash flows.

If we focus more specifically in 2014, it’s setting up to be an exciting year for us here at Encana. We’ve had a lot of change -- I think that’s probably an understatement if you ask our team. But that work is largely complete and we are now focused on executing our strategy.

In particular, some areas we're putting emphasis on is focus on growing our cash flow, not on volumes. We're improving our margins and netbacks based on our capital allocation process and our focus on efficiency. We intend to unlock value through our Royalty business IPO, which is targeted for completion by midyear and the complete appraisal on two new opportunities for the company in the Willesden Green portion of Duvernay and the TMS.

Just to give you a bit of an update as we’re halfway through the first quarter on our performance and our growth areas. In the Montney, we currently have nine rigs running. Our fifth well pad in Gordondale is now being completed and scheduled to begin production through permanent facilities in the second quarter.

In the Duvernay we have five rigs running. Our first multi-well pad is underway with two wells on production and 8 more planned for the pad. Drilling of the remaining six wells will be initiated in March after we complete pad construction.

In the Willesden Green portion of Duvernay, our latest wells are showing improvement toward achieving commercial type curve performance. In the DJ basin, we are now up to six rigs, which is up from two last year. Recently we set a drilling record of 8.6 days from spud to rig release versus a 13-day average in 2013.

In the San Juan, we have one rig running as we speak. Production performance on our latest well was very good with the 30 day IP of approximately 450 barrels per day, which has expanded our tier 1 or core well inventory area. We also had excellent results from our drilling program there with the latest spud to rig release was 10.75 days versus a 15 day average in 2013. And we continue to work with the BOM to improve the timing of realizing our drilling permits and our goal of reaching three rig by approximately mid-year.

In the TMS, we now have two rigs drilling to achieve early appraisal results. And in our base areas, we’re very focused on reducing the decline rate through additional focus right across our production operations.

Our strategy is all about growing value as opposed to focusing on volumes. By focusing our capital on our 5 core growth areas, we are funding projects that generate the highest netbacks and provide the greatest returns. We expect to see immediate value creation in 2014 as we focus on higher margin production.

If you look at the plot which shows the blue, which is our base production versus the green which is our growth area, you will see that the cash flow per unit of production is more than twice as large in our focused growth areas. This is why we are confident that over time our focus on value instead of volume will deliver the best results for our shareholders. Through disciplined focus on generating profitable growth, we believe we will drive consistently shareholder value. Our capital is focused on the areas with quality returns and running room. We are working to continue to reduce our cost structures to generate higher netbacks and drive capital efficiency in our core plays. We plan to adhere to our business model that is sustainable through the commodity cycle, grow our cash flow per share and maintain the integrity of our balance sheet. Ultimately our goal is to grow our shareholder value and we believe we are on the right path.

Looking forward to 2014, we’ve hit the ground running. We are clear on our priorities and targets. We have new energy and focus right across our business and we know what we need to achieve in our core growth areas and have exciting new focus on our base.

To close, I’d just like to thank our team and our shareholders for their patience and perseverance as we worked to reposition Encana to get back to winning. I’ve got my team with me this morning and we’d be happy to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions]. We’ll now begin the questions-and-answer session and go to the first caller. Your first question comes from the line of Greg Pardy of RBC Capital Markets. Your line is open.

Greg Pardy – RBC Capital Markets

Thanks. Thanks, good morning, all. Doug, just a few questions on different areas, but just play wise with the San Juan, I was surprised you’re only running one rig, is that really having to do deal with lease permits? On the Duvernay, could you dig into a little bit in terms of what's going on? Perhaps that's for Mike, but in addition to that will you be providing more regular updates around the Duvernay sort of between quarters? And two more quick ones just on the Wilrich, how are you thinking about that asset right now? And lastly, I just want to get a sense on cash taxes for 2014 from Sherri if you could? Thanks very much.

Doug Suttles

Yeah, Greg, thanks for your questions. Thanks for joining us. On the San Juan, you know I think when we rolled out the strategy and talked about the growth areas, we said that the challenge at the moment there was actually working with the BLM to speed up the permitting process. And we’ve been putting a considerable amount of effort in that area. Our plan all along was to ramp up to three rigs by about mid-year as we worked on that. I mean these wells, thankfully, the drilling performance is strong. So we go through a lot of wells quite quickly. So we need to make sure before we ramp up rigs we have permits in hand.

So I think we’re making progress there. We’re trying to help what we can do from our end in working with the BLM. But I think it’s basically where we expect it to be. The good surprise there was what we call the Tier 2 well came in at Tier 1 performance which has expanded the area. On the Duvernay, I think we’ll have to look, maybe take that question offline with Ryder and his team about how we could provide additional updates on that. On the Wilrich and the greater Bighorn areas, you know this is not a growth area at the moment. And as you know, we’ve largely pulled all of our capital back except for in those five core areas and across not only the Wilrich, but across all of our base, we’re now focused on operating efficiencies which is about reducing decline and making sure we’re running that portion of our business as well as we can. And just before I finish, I’ll hand to Mike just in case he has any additional comments to make and then we’ll pass to Sherri for cash taxes.

Michael McAllister

Yeah, in the Duvernay, as you know we’re – the North Duvernay segment is our area of growth, got to commercial type curve, actually better than commercial type curves. And so that’s really going to be our focus for commercial development with our first 8-well pad. We’re actually under construction right now to accommodate another six wells and two wells on production. And I’m very pleased with our performance in terms of starting to see efficiencies and completions as was explained earlier on the call. I’ll turn it back to Doug here now, sorry, Sherri.

Sherri Brillon

Hi, just a little around, maybe I’ll talk a little bit about 2013 cash taxes, because we did have an additional current tax recovery of $25 million in the quarter. So that brought us up to about $190 million for the year. The recoveries in ’13 were really related to prior period amount. So those included things like the impact of recently enacted legislation that was enacted during the year as well as a recovery of tax due to the carry back of U.S. alternative minimum tax losses to prior years. So we continue to go through our tax determination each quarter and they will vary because we are looking behind that's relative to a good number of tax losses that are available.

What is our estimated cash tax for 2014? At this point, our models would put in that we’re paying income taxes of less than $50 million for ’14 and this is really before any kind of AMD transaction.

Greg Pardy – RBC Capital Markets

Great, thanks all.

Doug Suttles

Thanks you.

Operator

Your next question comes from the line of Matt Portillo of TPH. Please go ahead.

Matthew Portillo – TPH

Good morning, guys, just a few quick questions from me. I wanted to see if we can get an update on kind of your Haynesville program. Saw that the volumes are still kind of in decline and wanted to see – I know that you’ve decelerated kind of the drilling side of it. But potentially on the completion side, where your uncompleted well count is and how we should think about kind of production out of that part of your basin?

Doug Suttles

Yeah, Matt. I’ll take a quick stab at and Mike can build on anything. I mean the Haynesville as we talked about, we stopped our drilling program there. I think Mike will confirm this. But I think we have five wells left to complete that we drilled last year. And so I think you just said six. So we’ve got six wells left to complete. But the Haynesville will be on decline in 2014. I think we’ve talked to a number of you about it. It’s an asset we like, but we don’t see it as competitive with other investment opportunities in our portfolio, nor consistent with our strategic focus right now which is to better balance our liquids and our gas volumes in the portfolio.

Matthew Portillo – TPH

And then just two other quick questions for me in terms of the DJ Basin, I was wondering if you could give us an update on how you guys are thinking about down-spacing in the play and how your wells are performing I guess, versus your expected type curves? And then my final question would just be around well cost in the TMS. I was wondering if we get an updated well cost for your TMS drilling program and how wells are performing versus your kind of RPS curves you provided?

Doug Suttles

Well, I think on the DJ, we’ll probably have to get back to our views on the down spacing side. I think the wells are largely performing at our tight curve expectations. I think the thing we’re most encouraged by is the cost keep coming down – it keeps driving efficiencies into the program as we go forward there as we go forward there. So I think that that’s probably if you will, if there’s any real change it’s actually just improvements on efficiencies that we’ve seen over the course of ’13. The TMS I think is as we’ve said we’ve just started re-drilling there. We’ve now got two rigs running. The focus was to start early to get as much data for appraisal as we could as early in the year as possible. So there’s not a lot to update there. As we've just literally in the past few weeks, we started drilling there.

Matthew Portillo – TPH

Great, I apologize. Just one last question from me. In regards to Deep Panuke, obviously we’ve seen the North East, pretty significant cold weather and very strong pricing in the first quarter. I was wondering if there’s any color or context that you could give to us around how we should think about kind of the first quarter pricing on those volumes and really how that may impact kind of your cash flows for the year?

Doug Suttles

Yeah you know – you guys can point us to a really reliable weather forecast that would help us with the later part of your question. I mean, the good news is we’re having the – it’s a good news if you cut me with a lot of gas production. We’re having a very cold weather which is pulling a lot of demand and obviously created very strong pricing here recently. And I think as Sherri mentioned it’s one place where we saw production on the daily price basis. So we’ve received very strong pricing here at the end of last year and through the first six weeks of the first quarter. I think it’s incredibly difficult given the current volatility that we know where this is going to land. Renee is on the call. Maybe I’d ask Renee if she has anything she’d like to add.

Renee Zemljak

No. Dough, I think that you covered that. I think the good news is that we do sell that volume into the smart work and it does receive an important pricing with transport.

Matthew Portillo – TPH

Thank you very much.

Sherri Brillon

A quick comment, this is Sherri. A quick comment that I added about $0.20 -- $0.18 to $0.20 on our fourth quarter natural gas price in Encana.

Operator

Your next question comes from line of Brian Singer with Goldman Sachs. Your line is open.

Brian Singer – Goldman Sachs

Thank you. Good morning. You’ve grown liquids production about 75,000 barrel-a-day guidance for ’14 would imply a lower rate of 2000 to 3000 sequentially versus the fourth quarter. Can you just add a little bit more color as to how much 2013 might have been a function of initiating new NGO facilities when there are declines kicking in or whether 2014 guidance is conservative, so then you could just help us understand the employed deceleration.

Doug Suttles

Yeah, Brian it’s a good question. There’s a couple of things. Clearly we did have some momentum in ’13 from changing how we received our liquids. It’s actually receiving the liquids and not just an uplift in the gas price. So there was some of that in the year. But we think that’s a good thing because it exposes us to those prices which we want to be exposed to. The big shift though and I think as we’ve shown as we rolled out our guidance is that the real uptick in liquids volume and ’14 was going to come in the second half of the year.

This is largely the result of reallocating capital. So we had capital allocated in 2013 to the number of plays which did have liquids. But we don’t see as core to our growth. Some didn’t meet the materiality thresholds and some in our view had the wrong liquids. They were ethane barrels as opposed to higher quality, higher value, condensate oil barrels. So as you turn to that capital and restart the programs, it does create a lag effect and that’s the real driver for the shape of the ’14 production.

Brian Singer – Goldman Sachs

That’s helpful. You may have just answered my second question that I’ll ask in anyway. On approved reserves, you talked a shifting resource out of PUD for why the gas reserves were revived down. There was also a negative liquids revision as well. I just wanted to see if you had clarity on what that representative is. It may be the same answer to the prior question.

Doug Suttles

Yeah, it basically is. And what's really happening here on reserves is that as we – typically in a couple of the plays like the Duvernay and the San Juan as you followed the reserve booking rules and shift the capital. You not only have the five year rule, but you’ve got the offset rule as well. So what you’re saying is just a shift. So what we now – the reserves we’ve just issued here at our press release and I think the detail comes out here in another month or so, I believe. It’s just aligned with our new allocation to capital.

Brian Singer – Goldman Sachs

I guess if you brought up the Duvernay and the San Juan, was your plan previously more aggressive and as its alternating, less aggressive now. You’ve taken PUDs off or --

Doug Suttles

No, that’s really not the case. In those areas the reserved movements are really noise because largely speaking, we’re just now starting to ramp up what I call commercial development and they weren’t significant barrels, reserves in those areas, they’re really in material.

Brian Singer – Goldman Sachs

Great, thank you.

Operator

Your next question comes from Bob Brackett with Bernstein. Your line is open.

Bob Brackett – Bernstein Research

Yes, can you hear me? I have a question. Anything you see in today is short term gas market that changes your view of the long term gas market.

Doug Suttles

Yeah, I’ll give a shot at that. Then I’ll hand it over to Renee. But of course, this is always – always speak with trepidation in this area because you know, as you’ll probably get it wrong. But I think our fundamental view going back to when we rolled out our strategy in the fall, it’s still there. We see gas marginally range down 350 to 450 for the next few years with regular upside going out in time. Clearly, this very cold winter has pulled a lot more gas out of storage than in more recent years and that’s created a new demand spline and obviously created stronger pricing. But I don’t think it’s fundamentally shifted our near to mid-term view, but Renee can probably add some color to that.

Renee Zemljak

That was very well said. The extreme winter that we’ve had so far this year will actually put a lot more demand in our forecast. That being said, we’re still going to require some cold gas displacement throughout the balance of the year. We won't require as such cold gas displacement as we had in 2013, so we think that we do have a new floor set for 2014 prices. So that’s good news, but longer term, we still see supply coming on strong especially from the Marcellus and Uintah. So we’ll be in an over-supply situation for the next few years to come which will put us in that range with the growth.

Bob Brackett – Bernstein Research

Yeah, I said just to clarify, you said Uintah, you meant Utica?

Renee Zemljak

I’m sorry, Utica, yes.

Bob Brackett – Bernstein Research

And then the quick one; you talked about saving a million and a half for well Duvernay. Can you give us from X to Y?

Doug Suttles

Mike is looking for the data just now. A lot of that was focused in on the completions performance. That was on a completions performance on our last two wells and it was related to basically being able to complete the two wells simultaneously. So while you’re fracking one, you’re wire lining the other ones, setting plugs and such as well as our water handling costs, we had water close by the lease, so that reduced our water handling cost. In terms of the X to Y, I’ll have to get back to you on that. Essentially we’ve got about million and a half on a per well basis.

Michael McAllister

I think Bob the one thing I’ll add is you know, I think we’ve talked about this previously. We’re moving to our first multi-well pad in the Duvernay and our goal there is to get the cost into the $15 million range is the first step to get it much lower than that over time. And the good news is, that sort of recent performance we started to see our steps in that direction.

Bob Brackett – Bernstein Research

Great, thank you.

Operator

Your next question comes from the line of Mike Dunn with FirstEnergy. Please go ahead.

Michael Dunn – FirstEnergy Capital

A couple of questions; the Clearwater, I noticed production was up, I think almost 25% quarter over quarter. Can you just provide some color on that and obviously it could be insightful to the upcoming IPO and I have a couple of follow-up questions.

Doug Suttles

Yeah, Mike. We have to cautious here because we’re in the IPO process. But what happened in 2013 was we put new emphasis in the Clearwater area particularly on the liquids potential and the team did a nice job. Also, we did see activity from people who were developing things on our acreage. It was actually – it will provide good performance in the fourth quarter for strictly on the liquid side.

Michael Dunn – FirstEnergy Capital

Great, and if I can, you know as I try to look out to your longer term guidance for cash flow growth et cetera. And try to get a sense of your capital efficiencies that are implied, I’m just curious as to the DJ basin. I know – I believe that at least some the capital that you’re spending there is benefitting from carries. I don’t know if you guys can provide any further color on sort of that greater Rockies, Piceance area. What portion of the carries in that area can you apply to drilling liquids versus the DJ basin? Thanks.

Doug Suttles

Well, in the DJ, we do have a joint venture there which has a partner carry in and I believe it’s in the neighborhood of about $1 million of well, is the rough range. We obviously have elsewhere in the Rockies have some JVs, but they’re mainly focused on our gas assets which is not a focus of our capital program. But in the DJ, we do have – we do have a joint venture which provides some capital carry.

Michael Dunn – FirstEnergy Capital

Okay. And I might as well ask and see what I can learn, but any sense, can you tell us how much you have left to earn on the carries there specific to the DJ basin?

Doug Suttles

I don’t have the details of that. I don’t think it’s a total earn out. I think it’s actually an opportunity on each well.

Michael Dunn – FirstEnergy Capital

Okay. Okay, thanks. That’s all for me.

Doug Suttles

You bet.

Operator

[Operator Instructions]. Your next question comes from the line of John Herrlin of Societe Generale. Please go ahead.

John Herrlin – Societe Generale

Thank you. One more try on the Duvernay. I believe last quarter you said besides, the wells were running around $12 million. Maybe I’m mistaken, but that’s my recollection. I’m wondering what you believe would be kind on a going forward basis with pads; it’s just a ball park.

Doug Suttles

John, you cut out just as the core of the question – can you repeat it for me?

John Herrlin – Societe Generale

Sorry. I believe in the last call you said besides the Duvernay wells, we’re running around $12 million. I was wondering with pad development, how low the fully loaded cost will end up being if you have a ball park to run that?

Doug Suttles

Yeah, I think what we’re trying to do as we move towards full resource play development is getting the well cost down in the very low teens. So this year, the first pad is to get it in the $15-ish million range headed towards $12 million is where we’re targeting.

John Herrlin – Societe Generale

All right, thank you.

Operator

Your next question comes from the line of Jeffery Campbell of Huey Brothers Investments [ph]. Please go ahead.

Unidentified Analyst

My first question, with regards to the DJ, I noticed – highlighted some very fast drilling time and a significant reduction in the completion cost and I was wondering if that [indiscernible] any possible upside on wells drilled in 2015 or was that already factored into the original plan?

Doug Suttles

Mike, do you want to pick that up?

Michael McAllister

Yeah. That was actually four of our latest wells are all under ten days with the lowest one being around that eight and a half days, so great drilling performance. And with respect to the completion of -- the completion efficiency that was pretty much about 34% reduction that's on the fracking operations.

Again, that's in related to going to slick water versus hybrid fracs or lower chemical class if you will, as well as 10 Emer [ph] simultaneous completion, so again similar to the Duvernay or re-fracking one well we are wire lining on the others. So it's a deeper frac that Sherri referenced a little earlier as well. So but we haven't changed our inventory or our planned drilling inventory for this year for the DJ.

Doug Suttles

Jeff, I hope it's a problem we have to address later in the year that if we continue to see the strong performance we're having a debate latter in the year that about more activity there, but we haven't changed the plan.

Unidentified Analyst

Okay. Thanks. I appreciate the color. My next question was with regard to the San Juan, if it's possible, I just wanted to see if I could understand exactly what the uplift was there? Was this well drilled in a different area? I mean, most of the drilling in San Juan is sort of in the corner area between San Juan [indiscernible] our most concentrated in that area. Did you drill into different area or was this simply a better than expected well, a better expected result in drilled in the same general area?

Doug Suttles

Yeah. We still drilled in the same general area, but we -- like in all these place, we try to identify, we call tier 1 that the core of the acreage, but clearly as you get out into some areas, there is less well density and we did have and do have a few wells this year to test our interpretation and this was a well drilled in what we call the tier two area and it's actually performing like a tier 1 well. So it's in a completely new area, it's just actually the well is performing considerably between our geologic premises what have it to be. So what the team is doing is, remapping the area that showing at tier 1 areas larger than we have very recently thought.

Unidentified Analyst

Okay. Thanks very much. My last question is kind of a little bit broader one. I think at some point there well drilled in a different area, I mean, most of the drilling in San Juan is sort of in the corner area of between San Juan [indiscernible] the development of LNG on the Canadian east coast seems to be moving along and I was just wondering if that would persuade you to hold on to the asset or just not even really effective? Thank you.

Doug Suttles

Well, I think first of all, we deep in it actually isn't -- we're not actually actively working to sell that asset. Right now, we just got it up on full production. It's performing quite well and currently it's performing quite well at the exact right time. But as we talked about strategically where we are [indiscernible] assets and we'll look at that and of course our view where the markets are and where they are headed will affect that. But literally as we said today, we are not actually, actively marketing deeper [ph].

Operator

At this time we have completed the question-and-answer session and will turn the call back to Mr. McRitchie.

Ryder McRitchie

Well, thank you every body for joining us this morning. Our conference call is now completed. If you have any follow-up questions please feel free to contact our IR department. Thanks again.

Operator

This concludes today's conference call. You may now disconnect.

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