Jul 24, 2014
Executives
Brian Dutton – Director, IR Doug Suttles – President and CEO Sherri Brillon – EVP and CFO Mike McAllister – EVP and COO David Hill – EVP, Exploration & Business Development Renee Zemljak – EVP, Midstream, Marketing & Fundamentals
Analysts
Greg Pardy – RBC Capital Markets Kyle Preston – National Bank Brian Singer – Goldman Sachs Mike Dunn – FirstEnergy Jason Bouvier – Scotia Capital Jeffrey Campbell – Tuohy Brothers Investment Research Dave Meats – Morningstar Sameer Uplenchwar – Global Hunter Securities Randy Ollenberger – BMO Capital Markets John Hurling – Societe Generale Jeoffrey Lambujon – TPH
Operator
Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation’s Second Quarter 2014, Conference Call.
As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode.
Following the presentation, we will conduct a question-and-answer session. (Operator Instructions).
For members of the media attending in a listen-only mode today, you may quote statements made by any of the Encana representative. 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.
Brian Dutton, Director of Investor Relations. Please go ahead, Mr.
Dutton.
Brian Dutton
Thank you, Jonathan, and welcome everyone for our second quarter results conference call. This call is being webcast and slides are available on our website at encana.com.
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 our webcast slides, as well as the advisory on Page 40 of Encana’s AIF dated February 20, 2014, the latter of which is available on SEDAR. In particular, I’d like to draw your attention to the material factors and assumptions in those advisories.
Encana prepared its financial statements with accordance with U.S. GAAP and reports its financial results in U.S.
dollars and U.S. protocol.
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 the progress we’ve made in implementing our new strategy, which was announced in early November of last year. Sherri Brillon, our CFO will then discuss Encana’s second quarter financial performance and Mike McAllister, our COO will provide some operational highlights from the quarter.
Following the slide presentation, we will have time for Q&A. I’ll now turn the call over to Doug Suttles.
Doug Suttles
Thanks, Brian and good morning, everyone. Thank you for joining us.
Encana delivered a solid second quarter performance. We continue to execute on our new strategy and transition our asset base.
There was a lot of activity on the A&D front during the last few months but it’s important to recognize that our overall business has been performing exceptionally well both from our original five growth assets as well as our base. We built significant momentum through the first half of the year and we expect to continue to deliver strong performance through the second half.
Before Sherri gets to the specific financial results, some highlights of our year include, we maintained our capital discipline by focusing a little more than 80% of our capital on our growth plays. We increased total liquids production by 49% to 68,000 barrels per day compared to the first six months of 2013.
We achieved operating and administrative cost reductions of about $100 million resulting from the realignment of our workforce as well as operating efficiencies. We closed the acquisition of our six new growth play in the world class Eagle Ford Shale.
We also closed the sale of our Jonah assets and the majority of the sale of our East Texas assets. We launched one of the largest IPOs in Canadian history by selling 46% interest in PrairieSky Royalty Limited.
We announced the agreement to sell our Bighorn assets for about $1.8 billion and we reduced our debt by about $1 billion to remain in a position of exceptional financial strength. All of the transactions we have executed over the last few months were undertaken with the goal to accelerate the transition of our asset base to a more balanced commodity mix, increase our margin and sharpen our focus on our core business.
By selling assets such as Jonah, East Texas and Bighorn, we have brought forward value from high-quality mature assets that we’re not receiving significant capital in our 2014 program. Through our acquisition in the world class Eagle Ford Shale, we have reinvested the proceeds from these natural gas weighted assets into a growth property with superb margins, low development risk and expected free cash flow generation in 2014.
We also unlocked tremendous value from the IPO of PrairieSky Royalty. This transaction was Canada’s fourth largest IPO ever based on the size of the initial offering and it created the company value at about $5 billion based on recent share price performance.
Prior to the IPO, as part of Encana’s asset base, these assets were contributing about $1 billion to the company’s enterprise value based on a five-times cash flow multiple. In aggregate, our very active A&D program over the first half of the year has simplified our business, high-graded our asset base and provided us with significant liquidity to be opportunistic going forward.
We believe that these transactions all contributed to the acceleration of our strategy and our goal of delivering value to our shareholders. I’ll now turn the call over to Sherri, who will provide an overview of our Q2 financial results.
Sherri Brillon
Thanks Doug, and good morning everyone. Encana’s second quarter financial results reflected strong performance of our asset base.
Our second quarter cash flow was $656 million or $0.89 per share, while operating earnings totaled $171 million or $0.23 per share. While total cash flow was down slightly from the second quarter of 2013, Encana’s upstream operating cash flow excluding hedges was up by roughly 22% compared to the second quarter of 2013.
Year-to-date, Encana’s cash flow of approximately $1.8 billion is up 41% year-over-year while $686 million in year-to-date operating earnings represents an increase of 61% from 2013 level. We saw strong growth in oil and NGL volumes through the quarter with an average rate of 68,000 barrels per day up about 43% versus Q2 of 2013.
Natural gas production was down slightly averaging about 2.5 billion cubic feet per day down by about 8% compared to the second quarter of 2013. This is a result of our capital investment focus in oil and liquids rich assets, divestitures and natural declines and was partially offset by production from Deep Panuke, further illustrating the enhanced profitability of our business, Encana’s net back during the quarter was $3.31 versus $2.63 per mcfe excluding hedging in the second quarter of 2013.
There are several factors beyond commodity prices which have contributed to Encana’s enhanced profitability in 2014. Liquid volumes during the first half of the year account for about $270 million increase in the revenues versus the first half of 2013.
We also continue to see a significant reduction in our normalized cost. Year-to-date we have achieved cost savings of about $100 million, a direct result of the implementation of our new strategy.
Removing the impact of long-term incentives restructuring charges, foreign exchange of one-time cost, administrative costs were down by approximately $25 million compared to the first six months of 2013. Upstream operating costs excluding the impact of long-term incentives and foreign exchange were down about $35 million and cancel costs were down by about $45 million.
These cost reductions are largely the result of realigning our workforce to be more consistent with our strategic focus as well as operational efficiencies achieved in both growth and base production assets. We are focused on leveraging technology and technical expertise across our business and we continue to actively seek ways to reduce cost, improve efficiencies, strengthening cash flow and maximize margins.
Encana’s balance sheet is significantly stronger than it’s been in recent history, due not only to the cash proceeds received from divestitures but also because we’re not longer out-spending our cash flow. In fact, we expect to generate free cash flow of about $500 million in 2014.
We ended the second quarter with about $2.7 billion of cash and cash equivalents after closing the $2.9 million Eagle Ford acquisition completing the redemption of $1 billion debt maturity as well. In addition, we have $4.3 billion of un-drawn bank link committed until 2018 so we have tremendous financial flexibility.
Net debt to debt adjusted cash flow was one times at the end of the quarter, compared to 1.5 times at year end and debt to adjusted capitalization was 29% compared to 36% at year end. Further reinforcing our strengthening balance sheet, the rating agency out split for Encana credit have improved over the past six months.
As a result of our increased liquid production from Eagle Ford acquisition, we increased our oil hedges during the quarter. As of June 30, we had hedged approximately 30,400 barrels per day of expected July to December 2014 oil production using WTI fixed price contract at an average price of $97.34 per barrel.
Our natural gas hedges remain largely unchanged. We have posted on our website this morning an update to our 2014 corporate guidance.
This update includes the impact that the Jonah and East Texas asset sale, the Eagle Ford acquisition and the impact of the IPO of PrairieSky Royalty but does not include the impact of any other A&D activities such as the recently announced disposition of our Bighorn properties or the sale of our power business. We will update once those transactions have closed.
Both Bighorn and Power sales are expected to close during the third quarter of this year. Due to the strong operating performance of our growth assets, our focus on cost efficiencies and strong commodity price performance, Encana’s transitioning to a more liquids-weighted portfolio while increasing overall cash flow from our initial 2014 guidance.
Our total cash flow range has increased to $3.4 billion to $3.6 billion from $2.4 billion to $2.5 billion in our original 2014 guidance, which was provided last December. This increase reflects the strong first quarter gas prices and the cash flow we expect to receive from our Eagle Ford assets in the second half of the year.
Maintaining capital disciple is a key focus for us, and as such the increase in our capital investment to $2.7 billion to $2.8 billion from our original guidance of $2.4 billion to $2.5 billion is largely attributable to the capital we expect to spend in Eagle Ford, which is cash flow positive in 2014 and does not reflect material increase of required capital to carry out our existing programs in other growth assets. We expect to generate significant cash flow in 2014 of approximately free cash flow in 2014 of approximately $500 million in excess of planned capital expenditures and expected dividend payments.
On the cost side, our guidance for operating expense and transportation and processing remains unchanged. That may have increased our DD&A expense to $1.50 per mcfe from $1.40 per mcfe in our previous 2014 guidance.
This increase is largely attributable to the impact of the Eagle Ford acquisition. The mid-point on revised guidance projects about 88,500 barrels per day of total oil and NGL production in 2014 and greater than 25% increase mid-point to mid-point compared to our original 2014 guidance which we disclosed last December.
With respect to the puts and cakes for our revised oil and NGL production guidance, we expect the Eagle Ford acquisition to contribute roughly 19,000 barrels per day on an annualized basis while divestitures that closed as of June 30, will resolve in a loss of about 4,000 barrels per day on an annualized basis. Total liquids production in the fourth quarter this year is expected to average between 105,000 and 110,000 barrels per day excluding the expected production from Bighorn.
For natural gas production, we are projecting an annual average of about 2.4 to 2.5 bcf per day, about 9% decrease mid-point to mid-point against our original 2014 natural gas guidance. This decrease is primarily due to the annualized impact of asset, sales and acquisitions then have closed year-to-date.
As I mentioned, the revised guidance does not include the impact of the announced sale of our Bighorn assets. Through the first six months of the year, production from Bighorn averaged 238 million cubic feet per day of natural gas and 11,500 barrels per day of liquids, including about 5,600 barrels per day of gas.
Overall the revised guidance reflects the success of our strategy execution. Compared to our original guidance cash flow was higher by about $1 billion and the natural gas production that was sold has been replaced with higher margin oil production.
I will now turn the call over to Mike Mc McAllister, who will provide an update on our Q2 operational highlights.
Mike McAllister
Thanks, Sherri and good morning everyone. Encana has achieved strong year-to-date operational performance across our entire portfolio as the performance is in line with or exceeding type curve expectations.
Our net backs excluding hedges for the first half of the year are 84% higher compared to the first half of 2013. This is largely a result of transition of our portfolio to a more liquids-weighted commodity mix and also reflects higher realized commodity prices during the first half of the year.
We continue to see increased efficiencies, lower cycle times, lower drilling and completion costs companywide. Our cost structures also continue to improve as teams focus on driving down costs.
Operating costs excluding long-term incentives were both 20% lower in the second quarter of 2014 when compared to the second quarter of 2013. We have seen organic liquids growth in the DJ Basin, San Juan, Duvernay and Montney, and this growth is expected to ramp up in the second half of 2014.
Finally, optimization of our base production continues to be a major focus for Encana and we have seen some excellent results from the projects that we’ve implemented to date. We are extremely pleased with the addition of the Eagle Ford as the sixth growth play in our portfolio.
The acquisition closed on June 20, and our team is quickly getting up to speed on the asset. We are currently operating three rigs in Eagle Ford and planned to bring a fourth rig on into the year.
Encana is planning to spend between $300 million and $320 million 2014 to drill 36 net wells. Our Eagle Ford field is expected to average to produce about 42,000 barrels of oil equivalent per day during second half 2014, contributing both 22,000 barrels oil of equivalent per day into our annual guidance with over 85% of the production being liquids.
As Sherri mentioned earlier, the Eagle Ford is currently a self-lending asset, we expect it to generate between $200 million to $250 million of free cash flow in the second half of 2014. We see tremendous upside potential as play as we leverage Encana’s expertise in developing resource plays by focusing on capital efficiency, optimizing well design, improving base decline.
Moving into 2015, we expect to increase our rig count plays with six rigs. Moving on now to the Montney, in the Montney, we continue to see impressive results from the high intensity completion design piloted and cut Anchorage.
Seven wells brought on-stream in Q2 are producing 100% over our prior type curves, with average initial rates of 12 million to 14 million cubic feet per day. Eight other wells have been completed using the same design, technique.
We expect to be on-stream in the third quarter. Initial results indicate liquid yields are also higher, ranging between 15 to 30 barrels per million cubic feet.
In a liquids rich Pipestone area, drilling efficiencies continued in the second quarter with drilling costs averaging $3 million per well which is about 9% improvement compared to first quarter of this year. We’re progressing, our long-term takeaway capacity plants in the Montney.
We successfully completed on-time and on-budget various infrastructure projects including a 60-million cubic feet per day expansion at our Dawson South compression station of 100 million cubic feet per day compressor facility at Pipestone and 10,000 barrel per day of liquids pipeline and condensate stabilizer at the six-month gas plant. In Gordon Dale, we have completed our 2014 drilling completions programs with 17 oil wells are expected to be online in the second half of this year.
Moving now to the DJ Basin. We continue to optimize and gain efficiencies in our DJ Basin program.
We have reduced the average spud to rig release cycle time by 3 days or nearly 30% faster than our 2013 average cycle time. During the quarter, we drilled sections link lateral flatter in only seven days, a new record for the play.
As well, we have drilled two sections or 10,000-foot lateral in just 18 days, spud to rig release. We added a second fracture to the DJ Basin during the quarter, we believe that this will help reduce our rig release to first sale cycle time and accelerate our cap on recovery across the entire DJ Basin program.
Lower cost and better production results have contributed to compelling economic metrics, and recently highlighted by independent industry analysts, Encana has delivered the most economic wells in the DJ Basin. Now on to the San Juan, in the San Juan, we are advancing commercial development while continuing to delineate the acreage.
Well performance has consistently been at or above expectations with initial production rates between 400 to 500 barrels of oil per day and we’re continuing to optimize our well designs in the play. Our drilling cycle times also continue to improve over time.
Year-to-date we have seen a 15% reduction of cycle times and during the second quarter we drilled our record well in 8.5 days spud to rig release. We’re encouraged by the improvements and permitting process timelines and we’ll continue to work with the local Bureau of Land Management office to further expedite the permitting process.
We currently have three rigs running in the play and plan on our fourth rig in the third quarter. Now on to the Duvernay, Encana has five rigs currently operating in the Duvernay Shale, we have drilled 12 wells, in that 24 gross wells year-to-date.
And we are currently drilling on three eight-well pads in the Simonette area. We have seen tremendous progress in drilling cycle times in the play, Encana has released five Simonette horizontal wells in the second quarter with an average spud to rig release in just under 30 days.
This represents a reduction of 17 days or 35% of our average in the first quarter of this year. It also translates the cost savings of about $1.5 million per well.
These five wells are the most long – are the longest horizontals in the play without collateral lengths of 7,000 feet. We have also tested five new Simonette horizontal wells in the second quarter.
All five wells are meeting or outperforming expectations. We now have 10 high-intensity completion Simonette horizontal wells that are meeting or exceeding our type curve expectations with initial production averaging 1,300 barrels of oil equivalent per day.
With respect to infrastructure expansion, we complete an expansion at the five 316242 facility which increased the growth capacity of this plant to 10,000 BOE per day. Additionally the 15 of 316221plant is on track with third quarter start up and it’s expected to increase the processing capacity to 55 million cubic feet per day and 10,000 barrels per day of condensate.
Now, on to the Tuscaloosa Marine Shale, the TMS team, has made significant progress in drilling longer laterals, reducing costs and achieve a normalized type curve performance. Encana’s wells drilled year-to-date are generally meeting our normalized type curve expectations with the Mathis and Lewis wells demonstrating record drillings days with spud to rig release times of 33 and 45 days and lateral lengths of 6,200 feet and 8,000 feet respective.
We continue to improve our drilling cycle times, increased lateral lengths because we are confident that our completion design and deliver reliable results. We have drilled 6 net wells year-to-date and we’re going to be running two rigs for the remainder of the year.
We remain on track to make the decision on commerciality by the end of this year. Turning to our base business, we have been extremely impressed by the level of focus across the organization on base production optimization projects offset product declines.
We have successfully executed various optimization programs already this year and we are well positioned to exceed our targeted 10% improvement from our expected decline rate of 28% to 30%. In the Haynesville, we have implemented a refract program with excellent results on our first two wells completed to date.
Initial production rates from both wells are 100% higher than expectations. We are planning to refract five more wells in the Haynesville in the third quarter and our teams are evaluating hundreds of wells to refract potential for refract potential license (ph) in the Haynesville, DJ Basin, Montney and Eagle Ford.
Another successful optimization project was the implementation of natural gas and NGL diversion strategy during the Restage of the plant, Resthaven plant outage. This resulted in 22 million cubic feet per day of continued production during a 90-day outage.
Some other strategy we implemented to date includes field progression and optimization and our artificial lift installation. The strong performance of our base business underscores our focus on profitability and enables us to accelerate the execution of our strategic initiatives.
I’ll now turn the call back to Doug.
Doug Suttles
Thanks Mike. While our A&D activity has taken much of the spotlight during the first half of the year, I hope from Mike comments this morning you can see how well our growth in base production assets have performed year-to-date as we transition the asset base and advance our strategy.
In the fourth quarter of last year, our original five-growth assets produced about 29,000 barrels per day of oil and NGLs, whereas in the guidance presented this morning, we expect these same five areas to almost double in liquids production to approximately 56,000 barrels per day of oil and natural gas in the fourth quarter of 2014. Layering in our recently acquired Eagle Ford asset, total liquids production from our six core growth areas is expected to average 92,000 barrels a day of oil and NGLs in the fourth quarter.
As we head into the second half of 2014, we remain focused on our disciplined and focused capital program our pre-hedge upstream operating cash flow is expected to be up 70% year-over-year. We expect to accelerate high margin growth plays.
We remain on track to make a decision on the commerciality of the TMS by year end. And we expect to have significantly advanced our appraisal in Williston Greene in the Duvernay.
We expect to finalize the Duvernay and Montney mid-stream solutions and we continue to focus on cost reductions and capital efficiency improvement across the business. With more than 80% of our capital, I’m sorry, with more than 80% forecasted increase in 2014 net backs.
Optimization of our base production performance continues and we expect to reduce our base decline to 25% to 27%. And we also will maintain our balance sheet integrity.
2014 is setting up to be a transformational year for Encana. By focusing our capital on our growth assets and now with the addition of the Eagle Ford as our sixth growth asset, we expect to see immediate value creation in 2014 as we focus on higher margin productions and value creation.
The blue portion of this diagram represents our base production, which is currently expected to deliver upstream operating cash flow of about $3.40 per mcfe in 2014 before taking into consideration our hedging activities, whereas, our growth assets, which are illustrated in green are expected to deliver $5.75 per mcfe this year. This is why we’re confident that over time our focus on value instead of production times will deliver the best results for our shareholders.
We continue to successfully execute on our strategy and meet our key benchmarks. We are rapidly transitioning our portfolio while achieving operational excellence and maintaining the balance sheet strength necessary for us to be optimistic.
We continue to see our cost structures coming down and are driving efficiencies into everything we do. Through the second half of the year, we will maintain a disciplined capital program and we expect to see strong results from both growth plays and continued out-performance from our base assets.
Through our disciplined focus on generating profitable growth, we are striving to grow shareholder value and we are positioned to continue to deliver on this objective in the second half of the year. Thank you.
And our team is ready to take your questions.
Operator
(Operator Instructions). Your first question comes from Greg Pardy with RBC Capital Markets.
Please go ahead.
Greg Pardy – RBC Capital Markets
Good morning. So three questions, I guess the first one is just in terms of digging into the Duvernay a little bit more.
Where are you in terms of your targeted cost productions on the wells? I think the third pad is new, can I guess we’d expect two-way well pads at the end of the third quarter.
So, how do we anticipate the third one? And then just with respect to the IPs that you’re talking about around 1,300 BOE per day.
I’m just wondering if we can get a split between gas and liquids on that. Second question and easy one is this $50 million still a good number in terms of cash taxes this year?
And then the last question, Doug, given all the progress that you guys have made, how does that square then with the targets in terms of both cash flow growth and production growth that you laid out back in November? Lot of questions.
Thanks very much.
Doug Suttles
Yes. Thanks Greg.
Good morning. Yes, maybe the longest was the questions for the first question I’ve ever had.
But let me make a couple of comments and I’ll turn it over to Mike on the Duvernay and Sherri on cash taxes. I mean, the headline on the Duvernay has to be that our drilling performance.
It’s – I think we’re very surprised by how quickly we’ve been reducing the drilling times and that’s actually accelerating our progress to hitting our sort of $12 million well targets, and Mike will talk some more about the details and he can also talk about the well rates. But clearly, I think we’re really pleased with the decision to move to developments this year and we’re well ahead of where we thought we’d be.
On your question on where we’re against our strategic targets with the plus 10% cash flow per share growth compounded over the period, yes, we’ll talk some more about this later. But clearly we’re getting there faster than we thought.
The portfolio transition we made with the divestments of some of our gas and then the movement into the Eagle Ford is clearly accelerated that progress. And we’re probably, as we get to the end of the year and talk about 2015 we’ll talk about that some more.
But we generally think we’re between one and two years ahead on our strategy delivery at this point. So, with that I’ll turn it over to Mike on the Duvernay.
Mike McAllister
Hi there Greg. With respect to our progress on our targeted well cost for the Duvernay, we’re really ahead of schedule here on the drilling and talking about these significant improvements we made in drilling wells.
And I think our latest well it’s kind of 25.5 days while we started at 45 days, so, incredibly happy with that. Now that’s on a 8-well pad where we have weak drilling operations.
So we’re seeing those efficiencies. With that we haven’t gotten into PH completions yet.
And we fully expect to start to see those cost efficiencies coming here to the end of the year. But that’s kind of where we’re seeing ourselves very, very encouraged on where we think we can take the cost.
With respect to the well rates, I quoted, it should take about 60% to 65% of that is being condensate but the rest being gas. And I’m not sure if there was another question Greg that you can line me on?
Greg Pardy – RBC Capital Markets
Yes, Mike, it was – what – maybe just a little bit more on that. So, I think it was $15 million per well that you – I believe that you guys had outlined earlier this year in the Duvernay.
Is that the number that you think you can beat this year?
Mike McAllister
That’s what we’re shooting for, you bet. Yes.
Greg Pardy – RBC Capital Markets
Okay. And then the other thing is, did you add another pad in the Duvernay or was it – or was the game-plan always that you would bring on three.
Just wondering when the third pad would come on?
Mike McAllister
Yes, we’ve just bought the third pad here in the second quarter. So, we’ve got three 8-well pads that we’re drilling on right now.
We have five rigs drilling.
Greg Pardy – RBC Capital Markets
Okay. And the third one would come on in the fourth quarter or would that be next year?
Mike McAllister
Probably into next year, I would be expecting.
Greg Pardy – RBC Capital Markets
Okay. Thanks very much.
Sherri Brillon
Hi Greg, its Sherri. Yes, your number of $50 million is good.
The updated guidance more or less reflects that current tax is $50 million for ‘14, before any additional dispositions or acquisitions. This really incorporates everything around the A&D transactions until the end of June.
Greg Pardy – RBC Capital Markets
Okay, great. Thanks all.
Sherri Brillon
Thanks.
Operator
Your next question comes from Kyle Preston with National Bank. Please go ahead.
Kyle Preston – National Bank
Yes, thanks. Good morning guys and congratulations on a solid quarter there.
I’ve just got a few questions for you here, I’ll shoot with them one at a time. Just, first on the Montney, I just noticed Q2 versus Q1, your liquids production was down about 3,000 barrels, gas was pretty flat.
I was just wondering if you can talk through that just what happened, was that just flushed condensate coming off or were you seeing lower liquids rates from some of the new wells?
Doug Suttles
Yes, Kyle, good question actually. And Mike can fill in the details here.
But fundamentally, we had a lot of production growth in the fourth quarter in what we call the Gordon Dale area. And we have some new Gordon Dale wells coming on in the second half of the year.
So it’s just a natural cycle of decline off the initial wells and the next wells.
Mike McAllister
Yes, you bet. We’re running tubing into a number of our Gordon Dale wells that we previously didn’t have tubing in them.
So that would have taken that volume down. As well as we have a number of plant outages that affected rates as well, there was a pin in our pipeline outage that also affected our condensate rates.
So that would have been what you would have seen I think it turns that they fall often.
Kyle Preston – National Bank
Okay. Thanks for that.
And just staying on the Montney there, just this recent IP rate just on the last seven wells, 12 million to 14 million cubic feet a day. I mean, how repeatable is that or you guys sort of in the sweet spot of the play or you think this is a result of your new completion method there that you can keep going forward?
Mike McAllister
We’re seeing this improvement up in the Northern part of cut Anchorage as well as in the South. We’ve basically cut our enterprise spacing in half from 160-foot to 80-food and with these essentially putting in double the amount of sand over that – over that same lateral length.
And we’re seeing significantly improved results. And that’s essentially happening across the play, not just one sweet spot I should say.
Kyle Preston – National Bank
Okay, thanks. And just moving on to a different question here, just related to your A&D activities.
I mean, can you guys make any comments on the potential sale of the Deep Panuke and whether or not you’re actively marketing any other assets?
Doug Suttles
Yes, Kyle. No, as you know, I think we don’t talk about our A&D activity unless we have a transaction to announce.
So, and there has been quite a bit of speculation over the last six or eight months about what we’re selling or buying, so we actually don’t comment on that.
Kyle Preston – National Bank
Okay. Thanks.
And one last question here just with respect to, you guys are obviously generating a lot of free cash flow here. I guess, that begs a question what are you going to do with this cash here, I mean, should we expect a bigger capital program next year, you’re still looking at other acquisition opportunities?
Doug Suttles
Yes. Actually the first thing Sherri is trying to find a bigger closet to put all the money in.
Now, but seriously, I think all along we’ve said a couple of things. One is, we have a real focus on discipline in our capital programs.
So I think you’ll have noticed in our new guidance. The only thing that shifted despite the addition of cash generation is the $300 million or so we’re putting in Eagle Ford.
The rest of the programs have stayed the same despite probably better than expected commodity price year-to-date. And in fact, you’ve heard some of the efficiencies Mike talked about, we’re actually getting more wells out of that capital that have been originally expected in those wells or in our growth areas.
We have not – we have not moved into new areas with that money. Beyond that we always have all the options that available we’re looking at what’s the best way to generate shareholder value.
So I think that all the options are out there. We think from debt reduction to some form of return to the shareholders to investing it back in the business.
Kyle Preston – National Bank
Okay, thanks. Just one last question here.
In your presentation you noticed that you’re seeing your base decline rate trend down there. I’m just wondering if you can talk through that a little bit, I mean, obviously a lot of the new wells you’re drilling in these core liquids growth plays I would assume have quite high initial decline rates.
How do you serve reconcile that, where are you seeing the improvement in the decline?
Mike McAllister
Well, we started, its Mike McAllister here. So, we really started an initiative with our new strategy to focus our truck back organization on our base production.
It’s an area where previously when you’re putting capital into 28 plays, the focus was on I believe it was focused on drilling wells and completing new wells. And what we’re finding is there is a real opportunity from productions operations standpoint for production engineering standpoint.
Just going back to those wells that we’ve drilled in the past number of years, and seeing if we can do look at liquid unloading, reducing gathering system pressures. It looks like that I mentioned two refracts in the Haynesville where we’ve gone back in with using a diverting agent essentially brought well rates up to $4 million a day that we’re just making a few Mcf when we first started so some tremendous results there.
And essentially it’s a program where we’re continuing to add to a portfolio of opportunities that we’re looking at investing in just the production operation standpoint.
Kyle Preston – National Bank
Okay. Thank you.
That’s it from me.
Doug Suttles
Thanks Kyle.
Operator
Your next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Brian Singer – Goldman Sachs
Thank you, good morning.
Doug Suttles
Good morning.
Brian Singer – Goldman Sachs
One or two, I would go back to the Montney. Can you provide a little bit more color on the change in the completion technique and what you’re doing there?
And then, whether the improvement in well performance you’re seeing, extends through the – as far as you can see to the life of the well or whether this is something that you think is going to be more concentrated in the initial rate during the initial couple of months?
Doug Suttles
Yes, Brian, Mike will fill in a lot of the details here. But I think what, one it’s quite early days.
But this is such a massive increase in wells rates that you got to believe ultimately it increases recovery, but we probably need some time to just verify and confirm that. But I think from a business perspective, what’s really exciting here is that our capital efficiency in our Montney program has improved dramatically with these completion design improvements.
We’re able to deliver the rate forecast using considerably less capital than originally forecasted. And so, our growth plans in the Montney haven’t changed because basically today we’re – our capital program fills up the existing infrastructure.
And what that means it’s going to take less capital to actually do that. But what’s really exciting is how quickly the team have come up with these ideas and implemented on the net ramping it up to – if you grow our standard design.
Mike McAllister
Yes. I mean, we’ve had wells on here for six to eight months.
We’re not seeing an increase – significant increase in the decline rates. The change that we made as we were fracking wells on slick water, cluster fracs if you will with 164-foot in the first phasing, we’ve basically cut that in half unto 82-foot in the first spacing.
And at that same time we’ve doubled up on our tonnage of sand over that same cluster. And we’re seeing significant improvements in our rates as we’ve talked about up to 100% of we where we previously.
With respect to whether it cuts across the entire play, everywhere we’ve tested this design up in the North, up in Saturn in and in the South down – it’s been working for us. So, we’re very, very confident and very pleased with the results that we’re seeing.
Brian Singer – Goldman Sachs
Great, thanks. And as a follow-up, on the Eagle Ford, you mentioned Eagle Ford as a growth asset.
I think on one of the earlier calls when the transaction was announced it may have been less clear what your plans were in terms of production trajectory. Has anything changed here or can you talk about that production trajectory expected in Eagle Ford?
Mike McAllister
Well, I think that you can pick up a couple of things. When we took over the asset, it had two rigs running, we’ve already added a third.
We did that actually, and we’ve only been operating that asset for a month now. We’ve got a fourth rig coming on later this year.
I would expect us to probably increase up towards six next year. And I would expect production to grow in 2015 I don’t want to set targets at this point for that.
But I would expect to see production growing in 2015.
Brian Singer – Goldman Sachs
Great. Thank you very much.
Operator
Your next question comes from Mike Dunn with FirstEnergy. Please go ahead.
Mike Dunn – FirstEnergy
Yes, good morning everyone, just maybe to follow-on Brian’s questions on the Eagle Ford. Firstly, the guidance for the second half of the year, I guess its 42,000 BOEs a day.
Can you just walk us through maybe where you’re at currently there and the trajectory through year-end? It is a pretty steep drop relative to Q1 and even where it looks like you were averaging at the back half of second quarter there?
And Doug, just maybe clearly you said you’d expected some growth in the Eagle Ford next year. I guess relative to, relative to what benchmark, the second half or the full year?
Thanks.
Mike McAllister
Yes, if you recall when we announced the transaction, I think we indicated that we’d expect that – like that time all that was out there was the first quarter results reported by the previous owner. And we said that that would probably be the high quarter for the year, largely because if I remember it correctly, they had gone from about 8 rigs down to 2.
And you saw the impact of that. And we’ve said we intended to ramp up the rig count in the play and we’ve been doing that.
And relative to production, the sort of growth I talked about it, it’s relative to the numbers we’re talking about for the second half, so the 42,000 BOE a day. Over the balance of the year, I think what you’ll see is the impact from adding the third and fourth rigs, we’ll see production grow as we head towards the exit of the year.
Mike Dunn – FirstEnergy
Okay. So maybe Doug, we think about the low-point being somewhere September-October?
Doug Suttles
Yes, I don’t think it’s – we’re not seeing because I think as we’ve ramped up the rig count and we’re doing some stuff with the operating base. We’re not – we’re not seeing a lot of decline across the balance of the year.
What we’d really see is the effect of adding the third and fourth rig show up as we head into the fourth quarter.
Mike Dunn – FirstEnergy
Great. And then, I apologize I might have missed this comment from Sherri earlier.
But Sherri, did I hear you say that the run rate liquids production, I guess Q4 or post, the Bighorn disposition would be 105,000 to 110,000 barrels a day?
Sherri Brillon
Yes, that’s correct.
Doug Suttles
Yes, that’s a 4Q average, just not sure.
Sherri Brillon
Yes, that’s fourth quarter average, and that’s correct.
Mike Dunn – FirstEnergy
Great. I’m sorry, I didn’t hear you clearly the first time.
Thank you. That’s it from me.
Operator
Your next question comes from Jason Bouvier with Scotia Capital. Please go ahead.
Jason Bouvier – Scotia Capital
Hi, thanks, couple of question guys. The first one was just in Colorado we understand they’re considering he change in the residential offset, in the area from 500 feet to 2,000 feet.
I guess, I’m hoping you guys could give us an update on the progress there. And I’m curious if they are successful in increasing the offsets, what sort of an impact that would have on you guys as current inventory.
Is it really relatively immaterial thing like less than 10% of the locations or is it a bigger deal as the offsets are increased?
Doug Suttles
Yes, Jason. I think so, just for everyone’s background, there were a large number of valid initiatives started for the November election.
Here, now that’s now been reduced to two. And there has been a lot of development in this space over the last week or 10 days which we see is positive.
The biggest being that some of the most important and significant politically are here in the State of Colorado have come out and openly oppose these initiatives as well as almost the entire, if not the entire business community across the state. People realize this is not an oil and gas issue, this is economic issue for the State of Colorado.
And we will see how that develops over the year. Us, and I think all of the businesses that are operating in the State of Colorado realizes this would be quite detrimental.
If implemented as stated in the initiative, the exact percentage is hard to tell in the implications. But it would have a significant impact to all the operators in the DJ basin with these issues came into force.
But it’s hard to speculate on whether one, whether that happens in two, how it would get implemented and what reaction people would have to.
Jason Bouvier – Scotia Capital
Okay, thanks. I appreciate that.
Second question was on the Montney, you guys obviously had some good success increase in the IP rates there to 12 million to 14 million. I think you guys said earlier, key to that was in the completion techniques and you’re doubling on the sand you put in.
I think you guys said capital efficiencies are much better now. But can you give us a sense of what the drill and complete cost would be associated with the wells where you’ve got the 12 million to 14 million cubic feet a day IP rate?
Mike McAllister
Yes, it’s been about 8 million for all the range. And where we’re – it would have been previously what’s that I think.
Jason Bouvier – Scotia Capital
Great. Well, that’s it from me guys.
Thanks.
Doug Suttles
Yes, thank you.
Operator
Your next question comes from Jeffrey Campbell with Tuohy Brothers Investment Research. Please go ahead.
Jeffrey Campbell – Tuohy Brothers Investment Research
Good morning.
Doug Suttles
Good morning.
Jeffrey Campbell – Tuohy Brothers Investment Research
The first question I want to ask was with regard to the refraction in Haynesville that you highlighted. Can you give us some kind of feeling maybe on the percentage basis, how the refract cost compared to a typically new well DNC?
And how much the original EUR might be being enhanced?
Doug Suttles
Yes, Mike can fill in the detail but I could tell you, it’s a whole lot less than drilling and completing a new well. But Mike can fill you in here.
Mike McAllister
Yes, of course we’re not drilling in the Haynesville right now. But the well cost for refract its running about $1 billion where the Haynesville previously would be running about $12 billion for a new well.
So you got a significant reduction in that. A little early to call in terms of the EUR that we would expect coming out of, coming out these refracts in terms of seeing how they decline.
But the initial results are very, very encouraging, like I said taking a well that’s just few mcf per day up to 4 million 3 million a day, tremendous payout there and rates of return on that investment.
Jeffrey Campbell – Tuohy Brothers Investment Research
Okay, great. Thank you.
You also highlighted that in the San Juan you had drilled 14 gross wells as of the end of June. Now that you’ve got three rigs running and you’re going to add a fourth in quarter three.
Can you give us some idea of how many gross rigs you hope to drill in the second half?
Doug Suttles
Yes, we’ll have to – we’ll just get back to you on that Jeff, we don’t have that at hand.
Jeffrey Campbell – Tuohy Brothers Investment Research
That’s fine. And the last thing I wanted to ask about was I guess kind of mostly a radical question.
But in the TMS another one big part of your appraisal has been to see consistency in the production of the wells. What I’m wondering is if you do see that predictable production profile that you want, quite a little bit lower EUR than your current target still support developing the play.
And please remind us of what your normalized type curve target is currently?
Doug Suttles
Yes, I’ve got David Hill with us here, who is our EVP of Exploration business. I’ll hand it over to him to talk about that.
But if you remember when we started the year, we had – late last year us, and others in the play we thought it started to figure out the completion design and we started to see what we call meeting expectations on the front end portion of the normalized type curve. We also – we talked about, it’s important these are not the easiest wells to drill but you can get that down and down successfully.
And then that would reduce the cost and then we wanted to see some time on the type curve, those are sort of the goals. One of the things we think is pretty material is, Mike went through it briefly but it’s a big milestone.
We just drilled an 8,000-foot lateral. I don’t know if it’s the longest lateral in the play but it’s got to be close.
So we’re seeing that come in, the drilling cost have been coming down and getting these wells to TD trouble-free it’s critical. And the normalized type curve performance has been strong.
So it’s just this combination. And David, what comments do you have?
David Hill
Yes, thanks Doug. I think you answered that pretty well.
And I think where we’re at on the cost, they continue to come down seeing very good performance after a rough start in the beginning of the year. And well over well, the team has been focusing on those drilling and completion cost.
Our completions have stabilized we still continue to look at frac attempted in the play as we develop our completion approach here at the end of the year. But the normalized type curve for us is performing on every well that we’ve done.
Our real goal is just to reach this lateral length. And if we can get that lateral length done, and here we’re focused on a bottom tool performance as well as mud-weights here in the curve and the lateral.
And once we get those nailed we’ll be feeling very confident. So, average EUR, 650,000 barrels of them 50,000 barrels.
And those look supportive to continue to drive our type well cost down.
Jeffrey Campbell – Tuohy Brothers Investment Research
Okay, that was great color. Thanks very much.
Operator
Your next question comes from Dave Meats with Morningstar. Please go ahead.
Dave Meats – Morningstar
Good morning, thanks. I just wanted to ask about the San Juan Basin.
Quickly you guys are now saying 400 to 500 barrels IPs. And I’m just wondering how repeatable these things those are across your position out there?
Doug Suttles
Well, just a couple of thoughts here really. One is, what we’ve been doing is a combination of developing the positioning continue to appraise the outer edges, what we look at is the tier 1 areas versus tier 2.
The good news is, the tier 1 is expanding. The best part of the play looks to be expanding.
The team’s also been experimenting with some changes in orientation and design which we’ve seen significant improvements in IP 30s of these wells. And as Mike mentioned the drilling and completion performance has been very, very strong.
So, what we see at the moment is the play is getting better compared to our expectations as it’s moving forward, the well performance is improving in what we consider the tier 1 area is expanding.
Dave Meats – Morningstar
Okay, that’s good color. Thank you very much.
And just one more question on the Haynesville, I know you’re not drilling there right now. Can you guys see any scenario in the next 12 to 18 months that would persuade you to go back to drilling there and maybe just grab what that would be?
Doug Suttles
Yes, we’ve talked about this at some length. And I always worry as we announced our strategy and people could see it implementing and they would read it as we’re exiting the gas business which is completely not the case.
We have some real high-quality gas assets in our portfolio. But today, under today’s market conditions, we don’t think it’s the time to invest into those.
But we’ve also said, we do see scenarios where gas price strengthens towards the back end of the decade. And areas like Haynesville are incredibly well positioned to benefit from that.
But what it basically means is we’d like to see a sustained stronger gas price in today’s price for us to go back into a significant drilling program there.
Dave Meats – Morningstar
Okay, thanks very much.
Operator
Your next question comes from Sameer Uplenchwar with Global Hunter Securities. Please go ahead.
Sameer Uplenchwar – Global Hunter Securities
Good morning guys, quick question on the fundamentals team. What’s the outlook for oil and gas over the next 18 months considering gas production has been running ahead of expectations?
Just trying to understand how the fundamental’s team is looking at and how management is looking at it? Thank you.
Doug Suttles
Yes, Renee Zemljak from Williston is with us and I’ll have her share her view. But from a strategic perspective we talked some about our longer, mid-to-longer term outlook on commodity prices when we announced our strategy.
And I’d say that fundamental look we still believe holds today. We talked about that some, we’re obviously enjoyed a nice benefit from a very cold winter.
But we also said I think in our first quarter call that our fundamental view has not changed. And I think both on North American gas prices and oil prices the mid-term view is still the same.
Obviously there is a lot of volatility today and maybe Renee, you’d like to share some color on that?
Renee Zemljak
Sure, thank you. Sameer, so, like Doug said, our fundamental outlook on prices hasn’t changed our view on natural gas prices in North Americas that would be ranged down somewhere between 350 to 450 outside of extreme weather events.
The downward pressure that we’re seeing on prices, most recently really has caused from cooler than normal weather coming on at the same time and we’re expecting to enter into the peak summer season at the same time that we have supply growth. So, we’re not surprised seeing the pressure that we’re currently experiencing on the gas prices.
But it doesn’t changed our longer term outlook on prices overall. And with regards to oil, our long-term view on oil for WTI is probably ranged from between $90 and $100.
And we haven’t changed our view on that either. The upside that we’ve seen most recently associated with that of course is due to the increased geopolitical chaos that’s currently going on.
It’s hard to predict how long that’s going to continue to add upside to our prices but borrowing that in base case scenarios, we expect oil to be between the $90 and $100.
Sameer Uplenchwar – Global Hunter Securities
Thank you. One last question from me on basis side, have you added as basis hedges 1Q to 2Q?
Renee Zemljak
We did layer in a couple eco-basis hedges in 2016 and 2017, a very small amount.
Sameer Uplenchwar – Global Hunter Securities
Could you give the – what the basis was?
Renee Zemljak
It’s reported in our financials.
Sameer Uplenchwar – Global Hunter Securities
Okay, thank you.
Renee Zemljak
Thank you.
Operator
Your next question comes from Randy Ollenberger with BMO Capital Markets. Please go ahead.
Randy Ollenberger – BMO Capital Markets
Good morning guys. Just three quick questions here.
First one, unless I missed it, I was just wondering where we stood on the Duvernay infrastructure, so what’s the latest on that in terms of timing and possible outcome? The second is on the Eagle Ford again, just how many Eagle Ford re-completions you might see and the kind of the incremental production adds from those and cost of those.
And then thirdly, Doug, I mean, you did mention what you might start thinking about doing with free cash flow, I recognize it’s relatively recently phenomena for you guys. But when you think about potential priority uses of free cash flow, how might you consider that between acquisitions either deepening or adding a seventh core area versus they returning cash to shareholders in the form of a buyback, we’re reducing debt of you can prioritize that?
And I’m thinking in particular you’re going to be getting another $1.8 billion or so in the third quarter and what you plan to do with all of that? Thanks.
Doug Suttles
Yes, thanks Randy. I think on Duvernay infrastructure, it’s a good question because it’s one of our strategic objectives this year is to come up with what we call the mid-stream solution there.
We also said that this is also for portion of the Montney as well. And what we have said is in the meantime, we continue to build ourselves and Mike talked about some of those projects which have been progressing quite well.
We’ve been running a process to test the market and see what the market will offer us here. We’ve been really pleased with the response, both from what you would probably consider to be traditional players, plus quite a bit of interest from new players coming in.
So, I think we’re on track to have make decision on what we’ll do by the end of the year. But at this point, it would be imprudent to talk much more about the details of that other than to say the project is making progress.
And we’ve seen a lot of market interest. On the Eagle Ford, it’s really early days to talk about what we might be able to do to what we’d call the base portion of the production to non-growth.
Our teams now have been operating the asset for about a month. I guess myself and Mike are pretty encouraged because they have identified a number of things they want to look closely into and see potential.
And hopefully as we get towards the latter part of the year, we can talk about that some more. But one thing specifically and it’s not just the Eagle Ford, what our team is currently studying is with the early success of refracts in the Haynesville is where else might that apply.
And one of the places that we’re looking at is in the Eagle Ford, but we’re also looking in other portions of the portfolio. On the free cash flow, the key point here is whatever we do we’ll be consistent with strategy and we’ve constantly said that the two factors which are driving this and are thinking around this is how we would – what we would do and how it would be accretive to the cash flow per share growth over that four-year period.
And how it would help us better balance our commodity mix. But I just stress here this is, we’re very, very focused on value.
In fact, if you know so production was slightly down, but our business is generating considerably more cash, even normalizing our price. And that cash flow performance will act considerably outpace what happens with volumes.
So, we’ll have to look at all those measures. And my team and our board will be in the conversation about what’s the best use of that cash.
And I really can’t comment any further at this point.
Randy Ollenberger – BMO Capital Markets
That’s great. Thanks.
Operator
Your next question comes from John Hurling with Societe Generale. Please go ahead.
John Hurling – Societe Generale
Yes, thanks. Would you consider following up on what Randy asked, would you consider addressing a higher dividend in terms of that kind of capital planning process with board?
Doug Suttles
John, when we announced our strategy, of course we reset our dividend and what we consider to be a sustainable level given our business plan and our outlook on commodity prices. And clearly as what we consider to be the underlying cash flow generation of the business improves, we’ll have to take a new look at the dividend.
Obviously after the decision taken by the board but given that we’re only 8 months into the strategy it’s probably a little premature. But it’s clearly something we have look at when we recognize that.
John Hurling – Societe Generale
Well, you have a lot more financial flexibility and free board that you give in your A&D transactions?
Doug Suttles
Yes, but I think though John, the way we have to look about this is our dividend needs to be sustainable out of operating cash.
John Hurling – Societe Generale
Agreed. Last one from me, I think of line pressures is in the DJ, some of your peers have been having some issues there I was wondering if you were?
Mike McAllister
Yes, we were having some there but there has been an expansion, I think it was Carnegie. And so that should alleviate the line pressure issues that we’re seeing I guess in the first half of the year.
John Hurling – Societe Generale
Okay, great. Thank you.
Operator
Your next question comes from Jeoffrey Lambujon with TPH. Please go ahead.
Jeoffrey Lambujon – TPH
Good morning, thanks for taking my question. So, just a couple more on the Montney, I was hoping to get some clarity around the completions and what the well looks like in terms of the number of stages of amount sand?
Doug Suttles
I see, what Jeoff, why don’t we get back to you so we can make sure we have the exact numbers on that. We can have someone from our team call you back.
Jeoffrey Lambujon – TPH
Okay, that sounds great. And then, I guess on the refracts, just wondering how you think about return on capital there and what you’re seeing in terms of scalability at this point?
Doug Suttles
Well, I think that Mike, I’ll let Mike pick up the scalability point. But the economics are probably the most robust in the portfolio based on our current outlook.
I think in the previous question, that we had on this that costs are relatively low for significant benefit. Now we do need to watch and see what if you will with the EUR from these, refracts are but we’re talking about payouts measured in just handful of months.
We’re not talking about years in this case.
Mike McAllister
Yes, and with respect to scalability I mean, you’ve got a five refract program right now talking to the team. They are seeing maybe another 30 that they’ve identified they’re kind of working their way through their inventory.
And I mean, it’s actually looking at hundreds if you will. But that’s still kind of sort of early days to give you any kind of exact number in terms of how many refracts in the Haynesville.
Jeoffrey Lambujon – TPH
Okay. And the 30, is that just in the Haynesville specifically?
Mike McAllister
Yes, that’s just Haynesville, those 30 wells I was talking about.
Jeoffrey Lambujon – TPH
Okay. And then my last question is on the San Juan, you guys are there right now, at the fourth and Q3 they will stay in from the permitting.
Just wondering how much room do you guys see in the asset going forward?
Doug Suttles
Jeoff, when we talked about our growth areas and sort of what it took to qualify, not only did it have to be liquids weighted. It also had to have what we consider to be scale and running room.
And the way we define that is an asset that we could see getting itself to somewhere around 50,000 BOE per day or bigger. We see that potential in the San Juan that would happen over a number of years so we think we’ve got considerable running room here.
We have done some small additions to our acreage recently. And we’ll continue to look for those opportunities.
We do like this play. It’s clearly not ever going to be the scale of an Eagle Ford or a Bakken or a Permian, it’s not just that large.
But it meets our scale criteria. And we see consisting growth through the play to our strategy period we talked about probably 2017.
Jeoffrey Lambujon – TPH
Thank you very much.
Operator
At this time, we have completed the question-and-answer session. And we’ll turn the call back to Mr.
Dutton.
Brian Dutton
Thank you, Jonathan and thank you everyone for joining us on the call this morning. Our conference call is now complete.