May 12, 2015
Executives
Brian Dutton - Director-Investor Relations Douglas James Suttles - President, Chief Executive Officer & Director Sherri A. Brillon - Chief Financial Officer & Executive Vice President Michael G.
McAllister - Chief Operating Officer & Executive Vice President Renee E. Zemljak - Executive VP-Midstream, Marketing & Fundamentals
Analysts
Sameer Uplenchwar - GMP Securities LP Benny C. K .
Wong - Morgan Stanley & Co. LLC Greg Pardy - RBC Capital Markets LLC Brian A.
Singer - Goldman Sachs & Co. Jeffrey L.
Campbell - Tuohy Brothers Investment Research, Inc. David Meats - Morningstar Research Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co.
Securities, Inc. Michael P.
Dunn - FirstEnergy Capital Corp. Menno Hulshof - TD Securities Barbara Anna Betanski - Addenda Capital, Inc.
Operator
Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's First Quarter 2015 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. 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 Brian Dutton, Director of Investor Relations. Please go ahead, Mr.
Dutton.
Brian Dutton - Director-Investor Relations
Thank you, operator, and welcome, everyone, to our First Quarter 2015 Results Conference Call. This call is being webcast and the 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 41 of Encana's AIF dated March 3, 2015, 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 prepares its financial statements in accordance with U.S. GAAP and reports its financial results in U.S.
dollars and protocol. Accordingly, any reference to dollars, reserves, resources or production information in the call will be in U.S.
dollars and after royalties, unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will provide the highlights of our first quarter results.
Sherri Brillon, our CFO, will then discuss Encana's financial results and Mike McAllister, our COO, will provide an update on our recent operating activities before we open up the call for Q&A. I'll now turn the call over to Doug Suttles.
Douglas James Suttles - President, Chief Executive Officer & Director
Thank you, Brian, and thanks, everyone, for joining us this morning. Encana delivered strong results during the first quarter of 2015, our first full quarter with our foremost strategic assets.
We're very pleased with our current portfolio, and we believe that our positions in the Permian, the Eagle Ford, Montney and Duvernay represent the best parts of the best plays in North America. We have a high degree of confidence in our ability to execute on the asset base and, as Mike McAllister will tell you in a few minutes, we are already delivering strong results in a quarter characterized by, first, our team continues to improve operational execution and drive innovation to improve well performance, increase well inventory and lower cost.
Consistent with our focus on investing in higher margin production, we directed 76% of our first quarter capital to our foremost strategic assets and delivered total liquids production growth of about 78%, compared to the first quarter of 2014. In contrast, natural gas volumes decreased by about 34%, compared to the first quarter of 2014.
Evidence of the portfolio transformation we delivered last year as we focused on value versus volumes. We generated strong first quarter cash flow of $495 million, up over 30% compared to the fourth quarter of last year.
Consistent with our focus on prudently managing our balance sheet, we completed a bought deal common share offering in March and used the net proceeds along with cash on hand, to retire approximately $1.3 billion of long-term debt in April. This brings our total debt redemption since the launch of our strategy in November of 2013 to $2.3 billion.
Finally, our safety results from the quarter continued to surpass historical performance. Throughout the first quarter and for the rest of the year, we remain focused on driving efficiency through innovation and taking prudent action to improve our cash flow generation and strengthen the balance sheet.
We have made tremendous progress in transitioning our asset base to a more balanced commodity mix. We have core positions in some of the highest netback basins in North American and are delivering attractive margins in the current environment.
We are well positioned to benefit as oil prices rise. Our expected liquids production growth from 2013 to 2015 represents a 60% compound annual growth rate.
For 2015, we expect oil and NGLs to represent about 35% of our total production, up from 13% when we launched our strategy in 2013. We also expect that roughly 78% of our liquids volumes will be comprised of high margin oil and condensate.
This gives us significant upside exposure to improvement in oil prices. Based on our guidance assumptions of $50 WTI oil price for the balance of the year, the sensitivity of our expected 2015 cash flow to a $10 movement in oil price is roughly $240 million.
That's roughly a 16% increase, based on the midpoint of our guidance range of $1.4 billion to $1.6 billion. We remain focused on growing value for our shareholders by investing in our best assets to grow our highest margin production and maximize cash flow growth.
Within 18 months of launching our strategy, we have simplified our portfolio from about 28 funded assets in 2013 to our four most strategic assets in 2015. Our Permian, Eagle Ford, Montney and Duvernay assets have the capability to grow profitably and advance our strategy, even in the current commodity price environment.
Assuming a $50 per barrel WTI pricing, our oil weighted assets, the Permian, Eagle Ford, and Duvernay are expected to deliver a weighted average netback of about $26 per barrel oil equivalent in 2015. Assuming a $3 per MMBtu NYMEX gas price, our gas weighted Montney asset is expected to deliver about a $1.10 per Mcfe netback.
Today, based on the assumption of an oil price that is nearly half of what it was in 2013, we are generating a higher netback from our four funded assets than we generated from the total portfolio two years ago. This is a direct result of our efforts to transition our portfolio and why we plan to direct about 80% of our 2015 capital to these four strategic assets.
Having repositioned our asset base, our portfolio now has the depth and scale to deliver profitable growth to our shareholders for many years to come. Combined, the Permian, Eagle Ford, Montney and Duvernay have over 10,000 identified drilling locations.
Viewed through a different lens, they have greater than 1.5 billion barrels oil equivalent of estimated 2P reserves and a further 2.4 billion barrels of oil equivalent of estimated 2C resources. Later in the call, Mike will illustrate why we have a high degree of confidence that our production from the Permian, Eagle Ford, Montney, and Duvernay assets will average about 270,000 barrels of oil equivalent per day in the fourth quarter, up about 35% year-over-year.
We believe we are positioned in the best rocks, a pillar of our strategy, and we are consistently drilling better wells, lowering our cost and increasing the well inventory in these high quality resources. While it is too early for us to discuss our plans for 2016, we do expect, with a capital program of roughly $2 billion, these four assets would continue to deliver significant growth in high margin liquids and cash flow.
I will now turn the call over to Sherri, our CFO, who will provide greater detail on our first quarter results.
Sherri A. Brillon - Chief Financial Officer & Executive Vice President
Thanks, Doug, and good morning, everyone. Encana's first quarter financial results reflect a strong performance of our assets and the transition of our portfolio to a more balanced, higher margin product mix.
We saw strong growth in oil and NGL volumes during the quarter, with an average production rate of 120,700 barrels per day, an increase of 78% compared to the first quarter of 2014. Oil and NGLs represented 28% of Encana's overall production volumes during the quarter, compared to only 13% one year ago.
We generated pre-hedged upstream operating cash flow of $454 million in the quarter, 57% which was generated from liquids production, compared to approximately 26% in Q1 of 2014. Total cash flow for the quarter was $495 million or $0.65 per share, while operating earnings were $9 million or $0.01 per share.
The per share figures reflect a weighted average diluted share count of approximately 758 million shares for the first quarter, reflecting the impact of our equity issuance. We recorded $1.2 billion after-tax impairment charge that impacted our first quarter net earnings.
Under U.S. GAAP full cost accounting, the carrying costs of Encana's oil and gas property is subject to a ceiling test on a quarterly basis.
The ceiling test impairment primarily resulted from the decline in the 12-month average trailing commodity prices. This charge is non-cash in nature and does not reflect necessarily the fair value of the assets.
On the cost side, we reported lower first quarter transportation and processing, operating production and mineral tax and administrative expenses totaling approximately $620 million, down about 14% compared to the Q1 of 2014, primarily due to divestitures, lower long-term incentive costs and lower U.S. Canadian dollar exchange rates.
We also received $838 million of net divestiture proceeds during the quarter, which we will use alongside our cash flow to fully fund our 2015 capital program. Our 2015 guidance remains largely unchanged.
Assuming $50 WTI and $3 NYMEX for the balance of 2015, we still expect to meet our cash flow guidance of $1.4 billion to $1.6 billion, despite the $165 million interest charge incurred in April as a result of the early redemption of our 2017 medium-term and 2018 notes. Through the year, we expect that the interest savings we will realize from the reduced debt levels and reduced borrowing costs, combined with our strong first quarter results and better than previously expected wellhead price realizations for the balance of the year, will offset that interest charge.
Our expected DD&A rate for the year has been reduced, reflecting the impact of the impairment charge incurred during the first quarter. If any are incurred through the year, additional impairment charges could further reduce our expected DD&A rate.
Capital discipline remains paramount as we execute our program with intense scrutiny on every dollar being spent. The profile of our capital spending is expected to be front-end loaded in 2015, reflecting the capital required to complete activities that were started in 2014 as a result of the nature of multi-well pad development.
We expect that roughly two-thirds of our capital will be spent in the first half of the year and remain on track to spend about $2 billion to $2.2 billion in 2015. Accordingly, our liquids growth profile will accelerate through the second half of the year, reflecting the cycle time of multi-well pad drilling as well as the impact of adverse weather in the Permian we saw during the first quarter.
Maintaining a solid balance sheet strength continues to be a top priority. We have taken significant steps to increase our liquidity and financial flexibility, positioning ourselves well in 2015 and beyond.
We use the proceeds from our equity issuance along with cash on hand to redeem approximately $1.3 billion of long-term debt, bringing the net debt levels to about $5.2 billion as of March 31. This straightens our balance sheet, enhances our credit metrics and provides greater flexibility for the execution of our strategy amidst a lower price environment.
The redemption of the 2017 and 2018 notes is expected to provide cost savings of about $200 million in future interest expenses. In addition, the implementation of our $2 billion U.S.
Commercial Paper Program is expected to reduce our borrowing costs by roughly $10 million to $15 million in 2015. We are prudently managing our debt levels as our 2015 capital spending plans and anticipated dividends are to be fully funded by our expected 2015 cash flow and proceeds we receive from divestitures which closed during the first quarter.
We also have revolving bank credit facilities of CAD3.5 billion in Canada and $1 billion in the U.S. committed until 2018, which provide us with significant liquidity.
The drive to continuously improve efficiencies and reduce cost is embedded in our business model and culture. Over the last several months, we have been actively and methodically working with our suppliers to reduce costs across the portfolio.
This operational focus supports one of our strategic goals of building a high performing and cost efficient company that is resilient through the price cycle. We view the commodity price downturn as an opportunity to structurally improve our profitability, and we are seeing the results come through.
This slide lists several examples of the current initiatives that are generating benefits for 2015 and beyond. When we announced our revised 2015 guidance in February, it included a 15% improvement or about $300 million in capital cost efficiencies as well as $75 million of direct operating cost savings.
We are well on our way to achieving these targets as we conclude our first quarter. I will now turn the call over to Mike McAllister.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Thank you, Sherri, and good morning, everyone. Our team is working hard to continuously improve well performance, lower cost across all our operations and increase well inventory.
We are leveraging the strength of our portfolio and the experience of our technical teams by taking proven drilling and completion techniques from areas such as Haynesville, Piceance and Montney, and applying them to the Permian, Eagle Ford and Duvernay. Encana continues to evolve its resource play hub model, applying techniques such as simultaneous drilling and completion operations, and integrated water hubs on multi-well pads across portfolio to drive greater productivity and cost efficiencies.
Through the optimization of well completions and the application of high intensity hydraulic fracturing, the company is increasing initial production rates and delivering stronger well performance. By maintaining a steady focus on our base production, we aim to minimize operational downtime, reduce production decline rates and lower direct operating costs.
In the Permian, we've started full resource play hub development or what we refer to as RPH. During the first quarter, we successfully implemented RPH on six multi-well pads.
In doing so, we now have a line of sight to reducing our well costs by 25%, due to operational efficiencies realized by RPH and other service cost reductions. As we move to 2015, we'll continue to assess our well inventory by reducing inter-well spacing, drilling stack laterals, and testing new zones.
To improve well productivity, we're testing higher intensity fracs, reduced cluster spacing. In the first quarter, we pumped up to 3,000 pounds of sand per lateral foot.
We plan to test up to 4,000 pounds per foot in the second quarter. We ran six horizontal and seven vertical rigs during the quarter, drilling 46 net wells, targeting the Wolfcamp A, Wolfcamp B, Wolfcamp C and Spraberry zones.
During part of the quarter, our production was impacted by adverse weather and facility downtime. Despite these challenges we exited the quarter averaging 38,000 BOE per day, an increase of 22% over our December production, I should say.
Currently Encana is on track to drill production to greater than 50,000 BOE per day in the fourth quarter. Our operational efficiencies and supply chain initiatives are starting to pay off as demonstrated by D&C costs highlighted in the bar chart.
We have realized cost savings of approximately $700,000 per well as compared to our Q4 averages. The implementation of resource play hub design in our fit-for-purpose rigs are resulting in decreased cycle times, as shown by the two referenced Midland County wells.
The Davidson well in blue was rig-released in Q4 and the Windham well in red was rig released in Q1. The difference in spud-to-rig release cycle time demonstrated a 13-day improvement or 35% reduction in cycle time.
We see this performance as repeatable as we employ RPH across the play. On the production side, we are extremely pleased with some of the recent well results, achieving rates of approximately 2,000 BOE per day after flowback.
This further illustrates our first simultaneous operations pad in the Permian Basin, showing drilling operations on the left and completion operations on the right. This is the four well pad targeting Wolfcamp A zone in the Howard County.
As you can see in the picture, meticulous logistical coordination is required to ensure personal safety and successful execution of the operation. The benefits of simultaneous operations are significant, and we have reduced our spud-to-initial-production times by approximately 30 days, which is meaningful when each well is producing greater than 1,000 barrels per day of oil.
As the Eagle Ford is also a relatively new addition to the portfolio, we are continuing to test innovative ideas to optimize new well performance and base production. For example, we have realized improved initial production rates by reducing cluster spacing and using higher proppant concentrations.
Companywide, we are focused on cost and Eagle Ford is doing its part. We have a line of sight to more than 20% reduction in well costs due to operational efficiencies, supply chain initiatives.
As in the Permian we are testing well spacing and stack pay to evaluate our future inventory in the play. Currently we are testing 30-acre inter-well spacing.
Based on early results, the team is encouraged that downspacing can be applicable in several areas throughout the field. We have also realized some promising early results in the Graben acreage.
Eagle Ford production averaged 42,000 BOE per day in the first quarter. As I mentioned in the previous slide, our Eagle Ford team continues to drive down costs.
Since we acquired the asset in the middle of last year, we have reduced our drilling and completion costs by approximately $1 million per well. We recently drilled a new pacesetter well at a cost of $6.4 million.
Operational efficiency is key and an issue such as upgrading our rig fleet to walking and batch setting capabilities has improved our spud-to-rig release time by approximately 12% relative to when we acquired the asset. Our continuous improvement efforts are shown by our pacesetter well that was drilled in approximately nine-and-a-half days, which is 42% faster than our Q3 average spud-to-rig release timing for the same well depth.
In the Graben, we have actively been testing reduced cluster spacing to help improve both short and long-term well performance. Based on the data we've collected a 60% improvement in 180-day production rates, and we believe we can now double the EUR per well.
Decreased cluster spacing and bigger fracs have not only helped Encana achieve higher production rates and larger EURs, but we've also seen sustained initial production rates. As shown in the well performance chart on the left, even after 180 days of production, our production rates are continuing to increase, demonstrating the success of our stimulations.
We are focused on base optimization. For example, in the first quarter, we have successfully reduced base declines by approximately 50% due to optimization of artificial lift systems.
We also continue to evaluate candidates for refracs where initial results of yielded IP30s of 140 barrels per day on average. Turning to the Duvernay.
Our plan for 2015 is to grow net production to greater than 15,000 BOE per day in the fourth quarter. By year-end, we'll have gross processing capacity of 105 million a day and 20,000 barrels a day of condensate stabilization.
As many of you know, our joint venture partner in the Duvernay, Brion, is currently paying 75% of total well and facility costs. This year, their contribution to development is expected to total between $600 million and $750 million.
Post 2015, there will be approximately $200 million to $250 million of remaining incremental funding being provided by our partner. In the Duvernay, the majority of our activity has been concentrated in the Simonette area.
We have made significant operational improvements as we transitioned from pilot to full RPH development. Our drilling times have improved from greater than 60 days in 2012 to less than 30 days on average in the most recent quarter.
Additionally, we have delivered pacesetter well with a drilling and completion cost of $11.2 million. In 2014, we invested in our water delivery and disposal system, I should say, and the facility is now operational and we're saving roughly 70% on our water handling costs.
A consistent theme across all of our plays is that improved well productivity strongly correlates with increased proppant concentration. The bottom-right plot shows the strong correlation between high proppant concentration and increased production in the Duvernay.
This dataset includes both Encana and third party wells. We're also testing optimal cluster spacing of 50 feet per cluster.
This photo illustrates a dual-frac spread operation on our 11 of 26 pads in the Duvernay, demonstrating our goal to drive efficiency through innovation and execution. By operating two frac spreads on the same 8-well pad, we're able to maximize runtime and pump nearly three times the stages per day than we can do with a single crew.
This innovation has resulted in approximately $700,000 of savings per well. Furthermore, we're able to reduce our spud-to-initial-production times by 26 days.
The Montney team is positioned to grow its production to greater than 140,000 BOE per day by year-end, representing growth of approximately 13% year-over-year. In order to achieve this growth objective a 200 million a day compressor station will be commissioned and brought online next month.
On March 31 of this year, we completed the sale of gas gathering compression assets supporting the development of Montney area to Veresen Midstream, who will provide these services under a fee-for-service arrangement. By unlocking value from these assets, we can redirect capital to strategic upstream opportunities, enhance our financial capability and maintain influencer facility construction and operatorship.
On the BC side of the Montney, our partner Mitsubishi is currently funding 70% of total well and associated facility costs. Post 2015, there will be approximately $550 million to $600 million of incremental funding being provided by our partner.
Encana has been developing the Montney play for over a decade and still continues to realize cost savings year-after-year. In Q1, we saw $1 million per well drilling and completion cost reduction, compared to our 2014 average.
We also continue to see great drilling results. The Montney team's fastest pacesetter well in Q1 was rig released in just 13 days.
Encana's water hub has been operating since September and has the capacity of 50,000 barrels per day. The hub provides significant cost savings for both our operating expense water disposal and capital expenditures to frac water sourcing and trucking in the Montney.
On the first pad that fully utilized the hub for completion activities, we realized cost savings of approximately $400,000 per well. A sharing knowledge across the organization and gaining insights from our competitors, Encana continues to improve our completion design in the Montney.
In 2014, we reduced our cluster spacing to 80 feet and realized a 70% uplift in well productivity, compared to original slickwater design. This year the team is focused on doubling proppant concentration from 1,000 pounds per foot to 2,000 pounds per foot.
By doubling the tonnage, we have achieved a 30% increase in overall well productivity. The improvements in capital efficiency and well productivity that we have achieved to-date, should help us meet our partnership production targets, while spending approximately $1 billion less over the next five years.
I'll now turn the call back to Doug.
Douglas James Suttles - President, Chief Executive Officer & Director
Thanks, Mike. As we look ahead to the rest of the year, we expect to achieve strong companywide liquids growth, up approximately 60% year-over-year with an annual average of between 130,000 barrels and 150,000 barrels per day.
About 78% of this liquids production is expected to be high value oil and condensate. Our continued focus on value over volumes will deliver significant production growth from our four most strategic assets.
We anticipate the total production from the Permian, Eagle Ford, Montney, and Duvernay will grow about 35% year-over-year in the fourth quarter of 2015, to at least 270,000 barrels oil equivalent per day. These four assets have some of the lowest supply costs in North America and are delivering attractive margins through this part of the commodity cycle.
We have budgeted a 15% improvement or about $300 million in capital cost efficiencies in 2015, and we are well on our way to achieving this target. Our focus on base optimization should also reduce decline rates and generate approximately $75 million or about another 15% improvement in direct operating cost savings.
As Sherri mentioned our focus on efficiency is part of our culture. We will continue to pursue opportunities to make further improvements in our corporate cost structure.
Encana has continued to successfully execute on our strategy and our first quarter results highlight the quality of our new portfolio, our focused capital investment and our prudent balance sheet management. We are driving through solid execution and innovations that are quickly being shared across the company.
Through team work, ingenuity and the application of our proven technical expertise, we continue to drill better wells, capture sustainable efficiencies and increase the inventory in our four most strategic assets, which are delivering significant high margin production growth. This makes Encana competitive at all points in the commodity cycle.
We will continue to proactively and prudently manage the balance sheet to preserve our financial flexibility and enhance our liquidity. In parallel, we will be ready to seize value accretive opportunities if we believe they serve the best long-term interest of our shareholders.
We are living within our means in 2015. Based on a $50 WTI oil price and a $3 NYMEX gas price, our 2015 capital program and anticipated dividends are fully funded.
We have all the necessary ingredients to deliver sustainable shareholder value and, through our focus and our drive, we will continue to build on the momentum through 2015. We'd now be happy to take any of your questions.
Operator
Your first question comes from the line of Sameer Uplenchwar of GMP Securities. Your line is open.
Sameer Uplenchwar - GMP Securities LP
Good morning, guys, congrats on a good quarter. I have two quick questions.
First is on the sustainability of the cost reductions on your operations, costs are coming down 25% or more, I'm just wondering if oil prices do move higher, gas prices do move higher, like how much of these savings are going to be there longer term? And I have a follow-up after that.
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, thanks Sameer; this is Doug. It's a good question and why we are emphasizing that, our savings are a result of a couple of different factors.
Clearly, part of it is service cost reductions. We've pursued those aggressively.
We started that at the end of last year. And actually, it's something we started as we were changing our portfolio.
But the other two elements that are critical here is execution performance, so this is focused on every single activity and doing it as good as you possibly can. And then actually, I think the biggest single driver is innovation, doing things smarter and better.
So some of these savings could try to leak out if you had a substantial, but I think it has to be a substantial increase in commodity price and activity increase. But largely, much of the savings I expect to stick.
Sameer Uplenchwar - GMP Securities LP
Got it. And then, like I'm just – the four assets you have discussed in detail in the presentation and in the release, I'm wondering about the other three: DJ Basin, San Juan, TMS.
Any update on those? Or they are non-core right now?
Or how do we think about those three?
Douglas James Suttles - President, Chief Executive Officer & Director
Sameer, with the big change, particularly in oil price that happened at the back end of last year, us and others all had to make some very clear capital choices. And we did that.
As you noticed from December to February, we reduced our capital guidance by about 25%. As we studied how best to do that, we came to the conclusion that in this part of the commodity cycle we needed to focus our capital in our four most strategic assets, and that's exactly what we did.
If we go back to November, we had about 44 rigs running across the company. As we sit here today, we have about 20, and only one of those is working outside the four.
We still have one rig running in the DJ. I should say places like the DJ and the San Juan have very good margins.
They are very profitable plays, but we had to make tough choices on our spend. And we decided we'd get the greatest efficiency and the greatest value creation by focusing on the four.
So that's the reason we made the choices we did.
Sameer Uplenchwar - GMP Securities LP
So are these core assets or non-core assets? I'm just trying to understand like on a long-term basis.
Douglas James Suttles - President, Chief Executive Officer & Director
Well, as we've talked about in the past, we really said we have in many ways seven core growth assets. We have the four: the Montney, the Duvernay, the Permian and the Eagle Ford, which are the most strategic.
And the reason for that is, is not only the quality of their margins, but their scale. The next two are the San Juan and the DJ.
The challenge we have there is slightly different, but can we achieve the necessary scale or not, it's not an issue of margins or returns, it's a scale issue. And then of course we hold this interesting option in the TMS.
Sameer Uplenchwar - GMP Securities LP
Got it. Thank you.
Operator
Your next question comes from the line of Benny Wong. Your line is open.
Benny C. K . Wong - Morgan Stanley & Co. LLC
Yeah. Thanks.
In regards to Eagle Ford recompletions, can you give us a sense of how many you guys recomplete in the first quarter? And remind us or even update us on how many candidates you have left?
And if you could provide any update on the strategy and pace you're thinking about them going forward would be great?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. I'll flip this over to Mike, but I think by recompletes you're probably referring to refracs?
Benny C. K . Wong - Morgan Stanley & Co. LLC
Yes.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Hi, Benny. Yeah, we just completed the two refracs here previously and both are performing very well.
We're monitoring them in terms of looking at their decline rates, making sure they match type curve, and they're looking pretty good right now. We have one planned here for the next quarter, another refrac, and we have multiple, somewhere in the 100 range, of potential refrac candidates as we look forward.
But it's all to be evaluated as we better understand the performance.
Douglas James Suttles - President, Chief Executive Officer & Director
If I add one thing to that, Benny, I think we've seen good early results. But I think our technical work suggests that we're only refracking a relatively small portion of the wellbore.
And we actually think the technology needs to advance before we push this scale. So we're going to go slow until the technology gets to where it needs to be.
Benny C. K . Wong - Morgan Stanley & Co. LLC
Great. And just jumping over to the Montney, you guys with the bigger fracs, you guys are seeing great success.
Is there a point where we can see upside to your type curve EURs? Are you anticipating at this point, it's more of an acceleration of alternate recovery rather than an increase?
Any color around that would be great.
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. Benny, it's a great question and it's interesting because there's so much additional early production, it can't all be acceleration.
But I'll let Mike fill you in on the details.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah, we're really, really encouraged with this next version of completion technique going to 2,000 pounds per foot, growing 1,000 pounds per foot. So on IP rates, we're seeing about a 30% increase, and we're monitoring again how these wells decline, but very encouraged from what we think we're going to see here in the EUR from these wells.
Benny C. K . Wong - Morgan Stanley & Co. LLC
Great. And just in regards to the faster drill times in the Montney, can you maybe give some color what's driving that down?
Are you guys doing something little more differently? Or, yeah, is it also availability of better crews as well?
Douglas James Suttles - President, Chief Executive Officer & Director
So as in all of our plays, we employ built-for-purpose rigs and walking rigs for pad drilling. That helps us in terms of driving the well costs down.
With respect to drill times, we're basically are looking at redesigning our bits as we go, and it's drill bit technology, Drill bit comes out of a whole, we're looking at redesigning at to make it basically more effective, getting better rates of penetration on the next hole. So it's continuous improvement.
It's kind of core to the way we do our work here at Encana.
Benny C. K . Wong - Morgan Stanley & Co. LLC
Great. And just a final question, I know you guys won't comment on potential non-core divestitures, but could you provide some color on what you're seeing in the A&D market?
We've been seeing some deals occur in the last couple of weeks. Are you guys seeing bid-ask spreads getting closer today or negotiations picking up in the space?
Douglas James Suttles - President, Chief Executive Officer & Director
Well, I think – Benny, this is Doug. I think that it's interesting.
If you just compare the first four-and-a-half months of 2015 to almost any previous year in activity is way down, whether it's M&A or A&D activity. That's probably not too surprising given the fairly quick and dramatic change in oil price in particular.
I think as time plays itself out, people are thinking about if prices are lower for longer, how do they optimize their portfolio and their business. And I would anticipate or at least wouldn't be surprised if activity gained some momentum through the year.
But I think, in general, I think the sense I have is it may be slightly less than people have been anticipating.
Benny C. K . Wong - Morgan Stanley & Co. LLC
Great. Thanks very much.
Operator
Your next question comes from the line of Greg Pardy. Your line is open.
Greg Pardy - RBC Capital Markets LLC
Thanks. Good morning.
Maybe couple of questions for Mike maybe to start out with, so the Duvernay I think you mentioned last year you'd achieved a drilling and completion cost at $12.4 million per well when you went to the pad drilling. I'm just wondering is there a target for 2015?
How much lower do you think cost could go there?
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah. That's right.
We actually in our latest pad, later in the year, I should say, we got to $12.4 million. We're targeting together under $11 million right now.
We actually have pacesetter pad is about $11 million well, per well cost is $11.2 million, but continued to drive the technology as well as our operating procedures, and we're continuing to push the cost down.
Greg Pardy - RBC Capital Markets LLC
Okay...
Douglas James Suttles - President, Chief Executive Officer & Director
I mean, yeah, Greg. Just add some color to that.
Mike and I were out in the Duvernay week-and-a-half ago, I think it was and met with the teams out there. And what's interesting is we've actually said they've done a great job, but we don't think they're anywhere close to finished.
We don't quite know exactly where that is, but I don't expect our momentum to stop. The pace will obviously mitigate some because we've gone to RPH.
But the thing Mike mentioned on the Montney, one of the newest things we may be do something slightly different than other companies in that we have drilling bit experts that work for the company. And we're now working on custom bit designs, which is actually significantly increasing our drilling performance, in particular meaning, we're getting whole sections drilled with single bit runs, which actually reduces time and cost.
So we're not yet ready to set the new target, but our old target was $12 million and we've already beaten that target, so now we got to figure how much lower we can go.
Greg Pardy - RBC Capital Markets LLC
Okay. Great.
No, thanks for that. And I know in the release you mentioned the exit rate of the Permian, how of much of that would have been oil and liquids?
Just curious.
Douglas James Suttles - President, Chief Executive Officer & Director
Mike, do you have that?
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yep.
Greg Pardy - RBC Capital Markets LLC
I can get back with you on that...
Douglas James Suttles - President, Chief Executive Officer & Director
The total liquids in the Permian is about 80%. It's gone down just slightly because in a lot of areas given the current ethane prices our midstreamers are rejecting ethane right now.
Greg Pardy - RBC Capital Markets LLC
Okay. Great.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah, that's about 50,000 BOE per day, but 4,000 BOE would be liquids.
Greg Pardy - RBC Capital Markets LLC
Okay. So that's the annual average?
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah.
Greg Pardy - RBC Capital Markets LLC
Okay, okay. Great.
And then last question from me is really the balance sheet. I mean, where do you want to see your balance sheet leverage in 2016?
And I know you're not going to comment specifically about M&A, but obviously non-core asset sales and some of the other questions that have come up already would conceivably lead you to believe that, hey, if you can get a good bid on some of these other assets, the DJ or the San Juan, those could be good fodder I think to improve the balance sheet, is that fair?
Douglas James Suttles - President, Chief Executive Officer & Director
You know, Greg, when we rolled the strategy out, we tried to say a few things at the time and one of which was the importance on the balance sheet in maintaining investment grade rating. And I think – and that was in a very different price environment.
As you saw us move into 2015, what we tried to reflect was between already announced and now closed divestments and cash flow, we'd fully fund our dividend and our capital this year. We actually do believe that if we can maintain a minimum of around $2 billion of capital, even in the bottom of the cycle, we actually drive good growth in our full core assets.
And we see the ability to do that. So I think what you'll see is us continue to manage the balance sheet very prudently.
We intend to maintain our investment grade rating and what you've seen is we've actually been retiring debt now two years in a row. It's a bit too early to say exactly where we'd position that for 2016, but I can tell you that it'll be prudently managed like we're doing right now.
Greg Pardy - RBC Capital Markets LLC
Okay. Thanks very much.
Operator
Your next question comes from the line of Brian Singer of Goldman Sachs. Your line is open.
Brian A. Singer - Goldman Sachs & Co.
You talked to a number of resource improvement opportunities in the Eagle Ford, the frac design, the cluster spacing, better decline rate management. Can you add some more color on what these all mean to EURs in the Eagle Ford?
And also what the impact would be on your recovery rate assumptions?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, Brian, just a couple early thoughts and then Mike can share it in. When we bought that position, we saw well inventory of about 400 locations, but we also saw some upside from downspacing.
There's an area we refer to as the Graben, which had been drilled early on in the life of the Eagle Ford with not particularly good results. We studied that pretty hard, believed there was some upside there.
We've now put I think six wells into it and four of which are performing considerably better than the type curve. We think that's not only a function of our new completion designs, we could see some things which maybe could be better done this time around.
So between the Graben and downspacing, there is upside potential on the well count. We're trying to quantify that.
And then also like other operators in the area, we're now looking at the Upper Eagle Ford and some potential that exists there. We're just starting to do the work around that, but that's an additional upside.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Hi, Brian; it's Mike McAllister here. Yeah, as I said on the call, we've been consistently increasing our sand concentrations and our inter-well spacing and our cluster spacing, I should say.
We're down to 25 feet now in our inter-cluster spacing. And our sand concentrations, we've moved those from 1,000 pounds per foot and now we're actually testing up to 4,000 pounds per foot.
And with that, and if you kind of look at the chart we showed in the Duvernay, there's a direct correlation to increase productivity with increased sand concentration. And we're seeing improved IPs, significantly improved IPs in all of our wells where we're actually getting up to 2,000 BOE per day.
But in the Graben where we're seeing up to almost up to a 1,000 BOE per day on our IPs, we're actually very encouraged and seeing increased EURs. Still studying the decline rates and seeing how things perform, but again it's a significant uplift from where we started when we first acquired the play.
Brian A. Singer - Goldman Sachs & Co.
Got it. Thanks.
And then you mentioned earlier you expect to stay relatively capital disciplined conservative. What combination of cost reductions – further cost reductions or what level of oil price would you need to see to allocate more capital and activity levels in the Eagle Ford, Permian and Montney?
Douglas James Suttles - President, Chief Executive Officer & Director
Brian, there's this kind of, if you will, nexus between our efficiency, commodity prices and our balance sheet that we've got to find the right place for. It's interesting, we – this is the dynamic world we're in at the moment.
We updated our guidance in February using a $50 oil price and a $3 gas price. I think I looked this morning and oil was trading at above $60, so there is some upside in there.
But I'd also remember in the first quarter, I saw numbers with a four on the front-end as well, which shows the volatility. So I think on commodity price, we've got to see some confidence that we're at a more sustained higher level, before we would shift our capital program.
And that's really to make sure we prudently mange the balance sheet.
Brian A. Singer - Goldman Sachs & Co.
Thank you.
Operator
Your next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Good morning. My first question was I noticed that you mentioned stacked pay potential in the Permian.
I was just wondering have you started any kind of stacked pilots yet? Or are you concentrating primarily on a zone or two at this time?
And if not, when do you think you might start to undertake some sort of stacked experiments in the Permian?
Douglas James Suttles - President, Chief Executive Officer & Director
Jeff, Mike will fill you in on the details, but the Permian we're trying to do three things simultaneously, and I'm encouraged by the early results. One is we've already gone to our Resource Play Hub multi-well development model, which is driving lot of efficiency in upfront.
I mean, you guys may appreciate it, but doing simultaneous drilling and completion operations is not common. We've done it elsewhere successfully.
It reduces cycle time, it cuts cost. I mean, Mike also mentioned, in the Duvernay two frac spreads on one pad.
We're told by the service company that pumped it, that's the first time it's ever been done in the world. And it generates substantial cost savings and cycle time benefits as well.
But the three things we're trying to do in the Permian is move forward on some of the zones with RPH development. The second thing we're trying is actually aggressively pursuing what do we think optimum development model is, and that's both inter-well spacing and completion intensity because as Mike mentioned we're looking at 3,000 pounds per foot and 4,000 pounds per foot on our frac designs.
And the third thing is we continue to appraise other horizons. We already are looking at chevroning, which is in my thinking it's vertical downspacing.
But we've got all three these going on simultaneously right now.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Hi, Jeff; it's Mike here. Yeah, we've been testing greater inter-cluster spacing or, should I say, reduced inter-cluster spacing and increased sand concentrations and seeing very encouraging results with respect to that in the Permian.
We've been testing the Wolfcamp A, Wolfcamp B and now are drilling the well into the Wolfcamp C, so basically looking at testing all of the zones as well as the Spraberry here. But as Doug mentioned within the zone, say, the Wolfcamp B, we're looking at not only just staying on the horizontal, but also moving, stacking vertically up basically 330-foot well spacing, but going from 200 foot to 300 foot vertically within the zones to test that production performance.
So moving along, we expect to be doing those tests this year, basically speeding up our learning curve, if you will, for optimal development.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay, great. Thank you.
And, Doug, I wanted to sort of ask a question that may seem a little odd, but I'm wondering what you think about optionality with regard to natural gas. There's been some discussion recently that the Haynesville might be for sale; I don't expect you to comment on that.
But there's also been some recent peer well results in the play that have been very strong. And I've covered in Canada for a long time, and I know that the Haynesville is a play, where you guys create a lot of innovation.
It's actually being moved to a number of other plays as we speak. So I'm just wondering are all natural gas assets created equal at this point, as liquids production is increasing?
Or are some more advantaged than others towards retaining?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, Jeff, I think it's interesting to think back. In the fall of 2013, we rolled our strategy out, one of the things we talked about is we thought that gas would likely trade and we predicated the strategy in a 3.50 to $4.50 world for a good part of the remainder of the decade.
We still believe that even though prices right now are not even at $3, as the market tries to balance a bit of oversupply. And I think when we look at the last wells we drilled in the Haynesville – we stopped drilling the Haynesville at the end of 2013, I think are if not the very best wells yet drilled in the Haynesville, amongst the very best.
We actually did 4,000 pounds per foot in the Haynesville in 2013 and delivered some incredibly strong wells. For us right now, clearly, what we're trying to do is get better balance of liquids at the moment.
And so that's where we're focusing our capital. But I will say that, I've been asked before do I think that what others are saying about the quality of the Haynesville is true?
I think I absolutely agree. I think that the well costs are coming down.
The well performance, particularly with these new high-intensity completions, are very strong, particularly if you're in the core of the play.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. Great.
Thank you. Appreciate it.
Operator
Your next question comes from the line of David Meats of Morningstar. Your line is open.
David Meats - Morningstar Research
Hey. Good morning, guys.
My question is again digging into the Permian a little bit. You've got quite a lot of inventory, 5,000 locations.
And I'm just wondering as you work through that, do you think supply costs or EURs will change in the more peripheral parts of that acreage?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, David, it's interesting because, as you guys know, the Permian, of course, you got the Permian's a number of things, it's the Midland Basin, it's Delaware Basin, it's a central platform, and it's all sorts of different zones, and they all vary. And what we're trying to do is simultaneously develop and assess this.
So we're over in Howard County drilling Wolfcamp A wells drilling very good wells. We're in Midland and in Martin County doing things in the Wolfcamp B, the Lower Spraberry.
We're also testing the Wolfcamp C. I think if you look at the history of all the plays, as you get better completion designs and you drive your efficiency up, the economics of the more peripheral areas start to look better.
They're never as good as the core though. They are never as good as the core, but clearly, us and others are both making better wells and taking cost out of the system.
And my sense is – I mean, we bought the position we bought because we believe it's in the core of the play, or the majority of position is in the core of the play.
David Meats - Morningstar Research
Fair enough. And with oil prices where they are right now and then with the volatility that you were just talking about, are you still actively adding hedge protection going forward at this point?
Or kind of waiting for prices to stabilize and then see what happens?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, you know what we do at the end of every quarter, and we just did it again today, is disclose our quarter-end hedge position. And we'll update that again at the end of 2Q.
We normally don't update that during the quarter.
David Meats - Morningstar Research
Okay. All right.
Well, that's all I've got. Congrats on the quarter.
Thanks a lot, guys.
Douglas James Suttles - President, Chief Executive Officer & Director
Thank you.
Operator
Your next question comes from the line of Jeoffrey Lambujon of Tudor Pickering Holt & Co. Your line is open.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Good morning. Thanks for taking my questions.
Just a follow-up on one of the previous ones on impacts to Eagle Ford EURs from the opportunities you all are now testing. Should we still view the older 250 to 700 range for EURs is valid?
Or has that moved higher maybe timed in your view?
Douglas James Suttles - President, Chief Executive Officer & Director
Well, Jeff, good insight there. I think what we've been doing is some of the areas we thought were at 250 range, we think are now getting higher.
We're not yet ready to update the type curve yet because we've got a limited number of wells, but basically those wells we saw as maybe the 250, which to be honest in today's price environment wouldn't be attractive. The question is can they be better than that and that's what we're testing, and the early results are pretty encouraging.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Okay. And then jumping over to the Permian and just looking at the Q1 liquids production there, up slightly versus the Q4 exit.
Obviously the Q1 exit is noticeably higher. How can we think about the quarterly ramp throughout the year there going forward?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, I think Sherri covered this earlier, but basically because we're ramping up and because we use multi-well pads, what it tends to mean is that it takes a little while to build the production because the cycle time on a multi-well pad is longer than a single-well pad. So the shape of our curve has considerable growth, particularly in the second half of the year.
The other impact here is as you pump these larger completions, these more high-intensity frac jobs, you hit peak production a bit later. Now the peak production is higher – quite a bit higher, but it does take a little longer to get there.
So the net result of that is, is fairly modest growth in the first half of the year and pretty strong growth in the second half.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Thank you.
Operator
Your next question comes from the line of Mike Remo (54:53). Your line is open.
Unknown Speaker
Hi. My question has been answered.
Thanks very much.
Douglas James Suttles - President, Chief Executive Officer & Director
Thanks, Mike.
Operator
Next question comes from the line of Mike Dunn. Your line is open.
Michael P. Dunn - FirstEnergy Capital Corp.
Hi, everyone. Just wanted to clarify, Doug, I think I heard you folks say that Q4 average production from the four core plays would be 270,000 BOEs a day, did I hear that correctly?
Douglas James Suttles - President, Chief Executive Officer & Director
Yes. That's correct.
Michael P. Dunn - FirstEnergy Capital Corp.
Okay. Thank you.
That's all from me.
Operator
Your next question comes from the line of Menno Hulshof of TD Securities. Your line is open.
Menno Hulshof - TD Securities
Thanks and good morning. I'll start with a question on the cost structure.
Looking to Canada, I noticed your gas costs were down quite a bit in Q1 relative to Q4 and even on a trailing fourth-quarter basis. So what drove that decrease?
And how much of that improvement would you consider to be repeatable?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. Some of this was actually – as you guys know, we had a lot of portfolio change last year.
So there are a number of factors which make kind of quarter-over-quarter a bit complicated. Some is what we bought and sold and some is the impact of even taking PrairieSky, which had royalty production in it and coming out.
But basically, I think the sort of numbers we're seeing here in the first quarter we believe are indicative of where we now expect costs to trend. Hopefully, they'll continue to go down, but I think as the portfolio is stabilizing, you should see less noise quarter-to-quarter.
Menno Hulshof - TD Securities
Okay. Perfect.
And then I might have missed this on this call earlier, but which plays drove the impairment charge in the U.S.?
Douglas James Suttles - President, Chief Executive Officer & Director
Sherri, why don't you pick that up?
Sherri A. Brillon - Chief Financial Officer & Executive Vice President
Hi. It's Sherri Brillon.
We don't really identify it on a play-by-play basis. We do our ceiling test according to U.S.
GAAP, which is done on a country-by-country basis.
Menno Hulshof - TD Securities
Okay. And then maybe I'll just wrap it up with Deep Panuke, is there any sort of an operational update that you can provide there?
Douglas James Suttles - President, Chief Executive Officer & Director
Well, I think what's interesting is with the onset of early water, which we talked about in 4Q of last year and in our February call, what we did is went to a seasonal operating strategy which actually optimizes the value of the assets, so we had a very good first quarter. I think for anyone who lives in the northeast of the U.S.
or the southeast of Canada felt the brunt of that, which created a good opportunity. We had strong operating performance off the facility.
I think our new seasonal strategy is maximizing the value. As we sit here today, we're shut in.
We expect to have Panuke shut in probably through the summertime and we'll resume production as we approach the winter. So far, we're pleased with the new strategy; it seems to be optimizing the value of the asset.
Menno Hulshof - TD Securities
Okay. Thanks, Doug.
That's it from me.
Operator
Your last question comes from the line of Barbara Betanski of Addenda. Your line is open.
Barbara Anna Betanski - Addenda Capital, Inc.
Hi. Thanks very much.
It's a Montney question and, in particular, egress capacity of the Montney. So I wanted to know what sort of a strategy you used in terms of balancing firm versus interruptible service?
And whether you were affected in any way by the TPL maintenance? And really as you look at the area longer-term in terms of growth out of the area, how are you strategizing for egress out of the area?
Are there any issues there?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. Thanks Barb.
Let me, Renee Zemljak runs our Midstream Marketing and Fundamental team is here. Let me have her pick that up for you.
Barbara Anna Betanski - Addenda Capital, Inc.
Thanks.
Renee E. Zemljak - Executive VP-Midstream, Marketing & Fundamentals
Hi, Barbara. Yes, we have had some minimal impacts as a result of the TCPL pressure issues for our Montney production.
That being said, some of our Montney is connected to both Alliance and TransCanada, so we've been able to divert some of that production. On a long-term basis, we have supported expansions from the region and we have secured firm access into the (59:03) market as well as we've secured firm access into the Pembina NGL transportation as well.
Barbara Anna Betanski - Addenda Capital, Inc.
So would it be fair to say that you're looking at your growth plans and you're matching your egress from capacity to your expected growth?
Renee E. Zemljak - Executive VP-Midstream, Marketing & Fundamentals
That's absolutely correct. Yes.
Barbara Anna Betanski - Addenda Capital, Inc.
Thank you very much.
Douglas James Suttles - President, Chief Executive Officer & Director
All right...
Operator
At this time, we – sorry, go ahead.
Douglas James Suttles - President, Chief Executive Officer & Director
Go ahead, operator.
Operator
Okay. At this time, we've completed the question-and-answer session.
I'll turn the call back over to Mr. Dutton.
Douglas James Suttles - President, Chief Executive Officer & Director
Very good. Before I hand it back to Brian, I just want to say a couple of quick things.
First of all, we do have our Annual Meeting of Shareholders this morning at 10 AM. And for those in the Calgary area, it was snowing yesterday morning, it's not snowing this morning, so I'm very pleased to say that.
So hopefully some of you will join us at the BMO Center. We have a live audio webcast of the meeting as well as the slides will be available on our website.
And just to close, when we set out our new strategy in November, it was all focused on value over volumes. We believe that's still the right strategy.
In fact, it may be even more important at the bottom of the cycle. I think part of the reason for our strong quarter in the first quarter is we have actually lots of access to create value by expanding margins, which is what we're very, very focused on, as well as growing our most critical high margin assets.
It was we believe a strong quarter and builds momentum as we head to the end of the year.
Brian Dutton - Director-Investor Relations
Thank you, Doug. Operator, our call is now complete.
Operator
This concludes today's conference call. You may now disconnect.