May 3, 2016
Executives
Brendan McCracken - Vice President, Investor Relations Douglas James Suttles - President, Chief Executive Officer & Director Michael G. McAllister - Chief Operating Officer & Executive Vice President Sherri A.
Brillon - Chief Financial Officer & Executive Vice President
Analysts
Greg Pardy - RBC Dominion Securities, Inc. Nick Lupick - AltaCorp Capital, Inc.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
David Meats - Morningstar, Inc. (Research)
Operator
Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's First Quarter 2016 Results 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 listen-only mode today, you may quote statements made by an 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 express consent of Encana Corporation.
I would now like to turn the conference call over to Brendan McCracken, Vice President of Investor Relations. Please go ahead, Mr.
McCracken.
Brendan McCracken - Vice President, Investor Relations
Thank you, operator. Welcome, everyone, to our first quarter 2016 results conference call.
This call is being webcast and the slides are available on our website at encanca.com. Before we get started, please take note of the advisory regarding forward-looking statements in the news release and at the end of our webcast slides.
Further advisory information is contained in our most recent Annual Information Form and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U.S.
GAAP and reports its financial results in U.S. dollars.
So references to dollars means U.S. dollars, and the reserves, resources and production information are all after royalties unless otherwise noted.
This morning, Doug Suttles, Encana's President and CEO, will provide the highlights of our first quarter results. Mike McAllister, our COO, will then provide some operational highlights.
And Sherri Brillon, our CFO, will then provide an overview of Encana's financial position before we open up the call up for Q&As. I will now turn the call over to Doug Suttles.
Douglas James Suttles - President, Chief Executive Officer & Director
Thanks, Brendan, and good morning, everyone. Thank you for joining us.
We delivered a very strong operational performance during the quarter. We are achieving basin-leading well results in each of our core four plays, both in terms of cost and production performance.
We are on track to meet or beat our 2016 cost savings target of $550 million. Operational innovation is the key driver of our 2016 program.
Just one quarter into this year, our teams are already meeting or beating their 2016 drilling and completion cost targets. As Mike will illustrate later, Encana is drilling some of the most productive and the lowest-cost wells in each of our core four plays.
Our focus on cost extends into every element of our business. During the quarter, we took decisive action to further lower our corporate costs and retire a portion of our fixed rate long-term debt.
We also added to our robust hedging program, with 75% of expected oil condensate and 85% of natural gas production hedged for the remainder of 2016, providing significant cash flow protection. We remain on track to meet or beat our 2016 guidance, and we expect to maintain the scale of our core four assets to position the business competitively for 2017 and beyond.
Our core four assets deliver premium net-back production and are expected to generate about 75% of total production in 2016. This is up from 60% in 2015.
The combination of our cost improvements and our operating performance in our high quality assets has positioned us to create value for our shareholders. You'll recall that on our Q4 results call we pointed to a $550 million cost reduction for 2016.
I'm pleased to report that we are already making tremendous progress against this sizeable target. Our Q1 costs are already within or better than our guidance ranges even though many of the initiatives behind these reductions are still in progress.
We are on track to reduce year-over-year field costs by $460 million. Our G&A in the first quarter was down 20% versus the fourth quarter of 2015.
We continue to proactively manage our balance sheet. In the first quarter, we retired $489 million of fixed term long-term debt at a cost of $400 million.
This not only reduced our principal, but we expect to save $30 million annually on interest. Reducing cost and capturing efficiencies remains a priority for the entire organization.
The operating cost reduction task force that was assembled in December has initiated over 1,000 initiatives across the company to lower our operating expenses. Our operating teams continue to implement initiatives identified by this task force to further reduce cost.
While the strengthening of the Canadian dollar will put pressure on some costs, we still expect to be within 2016 guidance ranges. It is important to note that all of these savings are largely permanent and will have even larger impact in 2017 as we benefit from their impact over a full year.
I'll now turn the call over to Mike to talk about our operating performance in the quarter.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Thanks, Doug. Excuse me.
Each of our core four assets are off to a great start for 2016. As Doug mentioned, we're already meeting or beating our full-year D&C cost targets in each asset.
Our field costs are all tracking within or better than their guidance ranges. Well productivity is strong across the board, and as a result we're on track to meet our full year production guidance.
With lower capital costs and better well performance, our production efficiency continues to improve. Specific to the Permian, our average Q1 D&C costs were $5.4 million per well.
At $720 per foot of lateral length, we believe this is the very leading edge of cost performance in the Midland Basin. Our Q1 pace-setter well at $4.6 million highlights the capability of our team and points to further reductions to come.
As an example, our latest drilling pace-setter well in Martin County was TD'd in less than nine days. The team has also done a tremendous job of reducing our vertical drilling requirements.
These efforts have reduced the capital required for our 2016 vertical program by a further $15 million. We have just wrapped up our drilling and completions operations on our 14-well pad in Midland County.
We drilled these 14 wells with four rigs and completed 485 stages with four frac spreads simultaneously. This innovative approach to development has dramatically reduced cycle time and cost.
We drilled and completed these wells in three months, which compares to 11 months with a single rig and frac spread. This approach has also accelerated the pace of learning.
From the first well on the pad to the last well, our drilling costs have dropped by 16%. The 14-well pad will come on production in Q2, and as a result we expect Permian production to grow over the quarter.
Beyond our cost leadership, we're also continuing to make great wells. A recent independent report pointed to Encana's long-term productivity as being amongst the very best in the basin.
Encana is the only producer to have well results in three counties rank in the top 10. This is consistent with our own benchmarking work.
As you can see on the chart on the bottom right, the 14 wells we brought on in Q1 are hitting and even outperforming our 1 million BOE type curve. All of this productivity is adding up, and Encana is now the second-largest producer in the core of the Midland Basin.
After growing over 17,000 BOE per day through 2015, the Eagle Ford has now largely stabilized at the production level we anticipate for the full-year average. The drop from the fourth quarter reflects the timing of new wells coming on-stream and shut-ins for offset frac operations.
We anticipate production in Eagle Ford to modestly grow in Q2. The Eagle Ford team has delivered a sixth consecutive quarter of cost improvements, with a new quarterly D&C cost average of $3.5 million per well.
This is 44% below the 2015 average. According to a recent independent industry report, these results put us on the leading edge of D&C cost performance.
We expect to increase our completions intensity for the remainder of the 2016 program, which will add $400,000 per well. Earlier in the year, we indicated that we targeted the Upper Eagle Ford.
On the bottom right of the slide, you can see two new Upper Eagle Ford wells. They have been performing within expectations and in line with the Lower Eagle Ford wells on the pad.
We are continuing to evaluate these results, with further delineation to occur next year. The remainder of our program has also been consistently outperforming on a well-productivity basis.
The same report reviewing our Permian production also highlights our basin-leading production performance in the Eagle Ford. By further optimizing our frac intensity, we expect to continue to deliver some of the most economic wells in the play.
Once again, we dramatically reduced the cost in the Duvernay. In Q1, our D&C costs averaged $8 million per well.
This is a 35% drop compared to our 2015 average and comes in effectively right at our 2016 target. The Q1 pace setter of $7.6 million points to more reductions to come.
Reductions are a result of cost efficiencies delivered by our dual drilling rigs, dual frac spreads approach, logistics, and service cost reductions. The new 10-29 plant came on-stream at the end of the quarter and we have begun ramping up production.
This brings our gross field processing capacity to 30,000 barrels a day of condensate and 155 million a day of gas. Today, Encana produces over half the Duvernay's total production from 30% of the play's wells.
This is in part due to our industry-leading well performance. Looking at all wells brought on-stream since 2014, Encana has averaged IP180 of greater than 1,000 BOE per day.
On a normalized basis, Encana makes up two-thirds of the top 40 wells in the play. The dramatic improvements to well costs and productivity continues to make the Duvernay competitive within our portfolio, excluding the benefit of the JV carry.
Similar to other plays, the team has done an excellent job on improving well costs in the Montney. We have reduced our well costs to $5 million per well, which is a 22% reduction compared to the 2015 average.
This represents one of the largest quarterly well cost reductions we have seen in the Montney in over five years. A pace-setting well cost of $4.6 million positions Encana as the top – one of the top performers in the play.
These cost reductions are combining with strong liquids-rich well performance on Encana's acreage to deliver very competitive returns. In Alberta, the initial Pipestone condensate production is strong.
We have drilled four wells in Pipestone this year. We now have these wells on-stream and have seen rates greater than 1,600 barrels per day of condensate and 2.6 million a day of gas.
The government of Alberta has recently announced the results of the royalty framework review. We are encouraged with these results as it positions the Alberta Montney to be competitive.
Our Tower wells continue to outperform expectations. This can be seen in the bottom right corner of the slide.
The five new wells onstream, have an average IP90 of greater than 1,300 BOE per day and 370 barrels a day of condensate. Finally, our four new Dawson South wells were all brought on-stream in April.
They are currently averaging 1,900 BOE per day with 500 barrels a day of condensate. We have a clear focus on liquids development and intend to grow liquids production to greater than 50,000 barrels per day by the end of 2018.
We look forward to discussing the Montney in much greater detail at our upcoming Montney Investor Event in New York City on May 17. I will now turn the call over to Sherri.
Sherri A. Brillon - Chief Financial Officer & Executive Vice President
Thanks, Mike. The pricing dynamics of Montney gas are currently a focus for the market as AECO pricing reflects the impact of one of the warmest North American winters on record.
Storage inventories across North America are high for this time of year. In Canada, we've seen a net storage injection throughout the first quarter.
With the potential for future storage restrictions and the requirement to use TCPL Mainline to clear the basin, AECO basis has widened considerably. It is important to note that unlike Appalachia, Western Canada is not physically short transportation capacity.
Although we do not disclose the specifics of our regional hedge programs, Encana uses both forward financial and term physical markets to hedge price exposure across the portfolio. Looking ahead, the forward market has set expectations for a directional return to a more normalized AECO price relationship.
This reflects the record low development activity in Western Canada as well as the trend of increasing demand. Ultimately, we believe that the combination of cost and well performance, condensate yields, and royalties, sets the Montney up to compete head-to-head with the Marcellus.
The collaborative approach of both producers and infrastructure owners has historically aligned market access with the pace of development in the Montney, and in our view this dynamic will continue. Our first quarter results demonstrate we are on track to achieve our 2016 guidance, which remains unchanged.
We continue to exercise discipline and focus with every investment decision that we make. In Q1, we directed 96% of capital to our four core plays: the Permian, Eagle Ford, Montney and Duvernay.
The profile of our capital spending program is front-end loaded in 2016. We expect to spend about 65% of our total capital program in the first half of the year.
The flexibility in our capital program enables us to quickly respond to changing market conditions. Our higher-margin production from our core four assets continues to make up a greater proportion of the total production.
In Q1, the core four assets contributed 70% of total production. This is up from 60% in 2015.
Our Q1 production and cash flow was squarely in line with our expectations, even though commodity prices were lower than anticipated. This was achieved as a result of our hedge position and our cost reductions running ahead of plan.
Our Q1 combined oil and condensate mix was 77%, in line with the guidance range of 75% to 80%. We continue to be on track for our core four production to decline from Q4 2015 to Q4 2016 by no more than 10%.
On our fourth quarter call, we also announced a further 20% reduction in – work force reduction, bringing our total work force reduction since 2013 to over 50%. As a result, our Q1 cash flow was impacted by a one-time restructuring charge of $31 million.
We continue to take decisive steps to lower our cost structures. Last quarter, we highlighted the cost savings we achieved on our transportation and processing, OpEx production, mineral, and other tax expense.
This quarter, we realized additional savings of $55 million or a 12% reduction in field costs. As we discussed in our last conference call, financial flexibility and liquidity are essential to maintaining a sustainable business through challenging market conditions.
We took decisive steps in 2015 to strengthen our balance sheet and lowered our debt by $2 billion. This past quarter, we successfully executed a debt tender and retired $489 million of senior notes at a cost of $400 million, lowering our annual interest expense on our senior notes by $30 million.
We have no long-term debt maturities until 2019. Our debt profile is very long-term in nature.
In fact, of our $4.2 billion of fixed long-term debt, three-quarters is not due until 2030 or later. We continue to access – we continue to have access to significant liquidity and are well positioned relative to our peers in this regard.
In addition to the $222 million of cash on our balance sheet as of March 31, we have immediate access to $3.3 billion of our $4.5 billion U.S.-dollar-denominated revolving facilities, which are in place until 2020. These unsecured facilities are fully committed and cannot be unilaterally terminated by the lenders.
There is one financial covenant on the facility, is debt to adjusted capitalization ratio not to exceed 60%. Since the launch of our strategy, we have continued to improve this ratio, reducing it each year from 36% at the year-end of 2013 to 29% at the end of Q1.
This is the only financial covenant on our credit facilities, and they are not subject to any covenants relating to cash flow, EBITDA, credit ratings or reserves. We are pleased with the recent announcement by Fitch which assigned Encana an investment-grade credit rating.
With three of the four rating agencies covering us at investment grade, we have seen no impact to our liquidity. Balance sheet focus and strength was front and center at our strategy launch, and we hope to continue to exercise strict capital discipline to preserve our financial flexibility.
Along with top-tier resource, operational excellence and capital allocation, market fundamentals is one of the four pillars of our strategy. The mandate of our market fundamentals team is to understand the trade winds, actively managing volatility, and forge a strong linkage with capital allocation.
Our hedging program provides increased confidence in our cash flow, thereby reducing risk and costs to executing our capital program. Historically, we have entered each year with about 50% of our production hedged.
Given today's environment, we have an even stronger hedge position. As of April 26, 2016, Encana has hedged approximately 75% of expected May to December 2016 oil and condensate, and 85% of natural gas production.
The distribution of our fixed-price natural gas and oil hedges ensure our near-term cash flow is protected, while allowing us to capitalize on a price recovery towards the end of the year. We have more protection in the near-term months of May, June, July and August, with hedges rolling off towards the end of the year.
As you can see in the chart above, we've also added a limited number of hedges for 2017, which are weighted towards the early part of the year. I will now turn the call back to Doug.
Douglas James Suttles - President, Chief Executive Officer & Director
Thanks, Sherri. Core to our vision of being the leading North American resource play company, we hold a strong belief that to be successful, we must be positioned in the best rocks.
Our portfolio is focused on "core of the core" positions in the top two Canadian resource plays, the Montney and Duvernay, and the top two U.S. resource plays, the Eagle Ford and the Permian.
We believe that these assets are among the most investable in North America and are very competitive globally. And when you consider our vast inventory of over 11,500 future well locations, Encana provides tremendous torque and exposure to recovery in commodity prices.
The impact of our cost performance improvements and our inventory quality has been material. The 22% to 44% drilling and completion cost reductions we've seen in the first quarter has increased our average after-tax returns at the well level considerably across each of our core four plays.
It has also improved our production efficiency by about 25%. We continue to believe in a focused portfolio.
In the near term, any proceeds received from asset sales this year, including the proceeds from the sale of our DJ Basin asset – which is expected to close by the end of this quarter – will be used to create further financial flexibility and balance sheet strength. Later in the year, if market conditions warrant, we may consider other options.
By simplifying our business, transitioning to a higher margin production, and becoming dramatically more efficient, we have advanced our strategy and positioned the company to create value for our shareholders. Our first quarter results highlight our strong operational execution, the discipline of our capital program, our focus on cost, and our commitment to maintaining a solid balance sheet.
I hope you come away from today's call with three key messages. First, we are on track to meet or beat our 2016 guidance, including our significant cost savings target of $550 million.
Second, the velocity of our drilling and completion cost improvements is proof that our culture of innovation and execution excellence is delivering basin-leading performance and improving returns. Third, we continue to create financial flexibility, which when combined with the quality of our core four assets and our operational execution positions us to meaningfully grow shareholder value.
Thank you for listening this morning, and my team and I are ready to take your questions.
Operator
Thank you, sir. Our first question is from Greg Pardy with RBC Capital Markets.
Please go ahead.
Greg Pardy - RBC Dominion Securities, Inc.
Yeah. Thanks, thanks.
Good morning and thanks for all that. Doug, I think on your year-end call you'd indicated that you thought the big four production would be down about 10% or so year-over-year in the fourth quarter of 2016.
Is that still your thinking?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, Greg. It – as we highlighted, things are pretty much exactly where we expect them to be.
Probably the only disappointment in the quarter from our perspective was particularly gas pricing, and obviously AECO basis was pretty low as it responded to the warm winter. But production's on track.
I think you probably heard Mike talk about, in two of the core four, we expect production to grow in the second quarter, in the Eagle Ford and the Permian, but a lot of this is just due to timing of activity. Probably the most obvious thing is this 14-well pad we've just completed in the Midland Basin, which I don't know if you've picked it up, we're pretty excited about this.
Significant reduction, and it's a substantial real test of the latest thinking on how you develop the Midland Basin.
Greg Pardy - RBC Dominion Securities, Inc.
Okay. Perfect.
The second thing is maybe just to go back to the D&C costs, cost reductions. I mean, highly impressive.
If you were to split those between cost reductions and process improvements, what would the rough split be?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, it's a good question. I'll make a couple of comments and maybe ask Mike to add some as well.
I think first, we continue to see cost reductions from service providers. It's a tough environment out there for absolutely everybody, and everyone, if you will, is doing their part to make sure that North America is competitive on a global stage, and I think you're seeing that in these results.
But it's a combination. I mean, to think that we did a spud-to-TD of our pace-setter well in the Permian at under 10 days is incredible.
That 14-well pad, I think we averaged around 13 days from spud to rig release – not spud to TD, but spud to rig release – which is down more than 50% from just a year and a half ago, so these numbers are incredible. But I think roughly, the proportion is still the majority, probably in the neighborhood of about two thirds, of the benefits are coming from execution performance.
Mike, buddy, I don't know if you have anything you want to add there.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah. Yeah, definitely, Doug.
The service costs played a part in the cost reductions, but our pad drilling philosophy and the procedures that we put in place really help, and helps on logistics and driving down costs. As an example, our sand distribution costs are spread – on that 14-well pad, were spread over four different frac spreads at the same time.
Same with the water distribution costs. Really helps you drive your cost structure down.
So I think a lot of the cost savings, two-thirds, as Doug said, are going to stick as we go through the cycle here.
Greg Pardy - RBC Dominion Securities, Inc.
Okay. Perfect.
And then just the last one for me is, you touched on the Eagle Ford; how core is the Eagle Ford, if you had to rank the big four?
Douglas James Suttles - President, Chief Executive Officer & Director
Boy, that feels like a tricky question, Greg. Clearly, the returns are – we've talked about this before – are very competitive.
And I kind of mentioned this at the tail end, by the way, with these cost reductions, and if you just use something like a $50 oil price and a $3 gas price, we've like doubled the rate of return on the average well we're drilling at a low deck. So these are wells which were generally in the low 20s% to 30% return and have moved well up into the 40s% or better with this substantial cost reduction.
We use this term production efficiency interchangeably with capital efficiency. It's basically how much volume we generate per dollar we spend, and we've improved that by about 25%.
So the other way to think about it is the supply cost, and we've talked about supply cost in the mid-30s in most of the places we're investing today, and that number is coming down. The Eagle Ford is competitive with that.
The one thing the Eagle Ford gives us is a tremendous amount of flexibility. The acreage is held.
We can actually, and this year's program is largely what we think of as a drill-to-fill program. So we're not building new facilities; we're filling in where we have excess facility capacity to get better capital efficiency.
But it's very competitive. It doesn't have the same scale as the Permian or the Montney, or the same growth potential that the Duvernay has.
That's probably the most significant difference in – that it has for us in the portfolio.
Greg Pardy - RBC Dominion Securities, Inc.
Okay. Great.
And the last one for me. You did mention that you'd potentially look at other options later in the year, which is fairly open-ended, but if we're going to read that into what kind of WTI price would be needed for you to start to think about expanding the program, is that how we should think about that comment?
Or am I reading things that aren't there?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. I wouldn't over-read it Greg.
I think that what we're really saying is, we've got a lot of flexibility. We have – we can ramp programs up and down quite quickly, as we've showed.
I mean, our capital was higher in the first quarter largely because, you remember, we reset the capital program in the middle of the quarter, in mid-February, and brought that down, and we're now operating at that lower capital spend rate. But it just shows we can ramp these programs up our down quite quickly.
I think Sherri outlined how we use our hedging program to protect cash flows, and as I mentioned, we're already making competitive returns. So this is a matter of confidence in the commodity price and how we manage the balance sheet.
And the only thing I was trying to highlight there was, we have a lot of flexibility. And we'll continue to monitor the market conditions, but we put a lot of emphasis on maintaining a solid balance sheet through this part of the cycle.
So all I was really trying to say is we've got a lot of choice here, as we think largely the supply-demand curve begins to come into balance as we head towards the end of the year.
Greg Pardy - RBC Dominion Securities, Inc.
Okay. Perfect.
Thanks very much.
Operator
Thank you. Our next question is from Nick Lupick with AltaCorp Capital.
Please go ahead.
Nick Lupick - AltaCorp Capital, Inc.
Yeah. Thanks.
Good morning, guys. Just a quick question for me on the DJ.
Obviously, we've sold that asset and I just wondered if you could give us a bit of an update on that, on the timing, maybe just what we're waiting for, maybe due diligence or what have you. And also if there's any expectation that the proceeds will change going forward.
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, Nick, thanks. No, the story on the DJ hasn't changed since December.
We're – I think we mentioned briefly there that we're still on track, we believe, to close by the end of this quarter. And the proceeds haven't changed; the deal terms haven't shifted.
And we keep working forward with Crestone, who is the purchaser, to get that closed by the end of the quarter, and I still think we're on track to achieve that.
Nick Lupick - AltaCorp Capital, Inc.
Perfect. Thank you.
Operator
Thank you. Our next question is from Jeffrey Campbell with Tuohy Brothers.
Please go ahead.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Good morning, and congratulations on the cost reductions. With that in mind, I was going to ask, with the evolving cost reduction, if you were to land towards the bottom end of the CapEx guidance, would you be more likely to take on another rig or put the money on the balance sheet?
Douglas James Suttles - President, Chief Executive Officer & Director
Well, you know, it's a good question, and actually there's a little bit of complexity in it. I think we indicated in the call in February that our guidance said $900 million to $1 billion, and I think I said in the call I'd be surprised if I saw that as $1 billion.
And you're seeing the performance our operating teams are delivering, and it does give us the flexibility. But a lot of it's going to be about second-order optimization: does it make sense to continue a program or keep a frac spread working a little longer than currently planned?
But it is the sort of flexibility we have. And as Greg asked about earlier, all I'm really trying to highlight is we have those options within it, and we'll continue to watch the performance.
Some of this performance is incredible. I mean, if you think about when we entered the Eagle Ford in the middle of 2014, wells cost $8 million, and in the first quarter, we drill wells for $3.5 million.
I think that's performance that can go head-to-head with absolutely anybody in that play. And we're a year and a bit into the Permian, and I think our well costs are leading edge and our well performance is leading edge.
And this isn't only Encana's assessment; these are independent groups are writing these stories. So it gives us that option, Jeff.
It's around the edges, though, and we'll just, as we get farther into the year, we'll be able to see, does it make sense? But we're talking a few tens of millions of dollars; that isn't substantial.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. That makes sense.
Slide four shows that D&C costs that we've been discussing are normalized to a 7,500-foot lateral, but the type curve on the same slide shows data based on an 8,500-foot lateral. I was just wondering what's the average lateral length that ECA is targeting for 2016 in the Permian?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, it does vary, and Mike will fill in, but one of the reasons we stuck that out there is some people are using longer type curves or longer well lengths for their type curves, so we're trying to be apples-to-apples. But just as an example, that 14-well pad that Mike talked about, our average well length's a little over 8,500 feet.
And by the way, I think if you look at the deck, there's some pretty cool photographs there. I don't know of anywhere in the world where anyone's put four modern 1,500-class drilling rigs on the same pad, and I'm pretty certain no one has ever put four frac spreads on the same pad and simultaneously completed 14 wells.
We actually had – recently we had I think it was five stick pipe and three coil units simultaneously drilling out those 14 wells. And this is what's driving this performance.
There are real savings generated by doing that, whether it's logistics or ancillary services, but I think this is what leading-edge operators are going to be doing.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
Yeah.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Thank you.
Michael G. McAllister - Chief Operating Officer & Executive Vice President
I don't know if you wanted me to add any more, but I think we're looking between 8,500-foot and 9,000-foot, would be kind of what we're targeting for lateral lengths this year.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay; thanks. I appreciate that.
Operator
Thank you. Our next question is from Jeoffrey Lambujon with Tudor, Pickering, Holt.
Please go ahead.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Thank you, good morning. Just two questions on CapEx.
First on allocation across the portfolio, I'm just thinking about the wide basin in Canada, again with little disclosure on your hedge protection there, which is understandable given your contribution to the overall Canadian gas production mix, and then keeping in mind a continued shift toward liquids-rich drilling, and also you mentioned Eagle Ford flexibility – are there other parts of the budget that are flexible as well, to where we could see incremental capital put to work in the U.S. where, again, you don't have that AECO basis issue and where you're seeing well costs improve, kind of to a greater degree versus targets for the year?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. Just a couple things on the flexibility, so the – if I start with the Montney in Canada, I mean this – even in today's low prices, you got to remember that we're – Mike's comment about growing liquids to 50,000 barrels a day over kind of the next two years.
And those liquids are largely condensate. And as you know, condensate here in Western Canada sells very close to WTI pricing.
So it's a quality product. And a lot of the return, even with low gas prices, comes from that.
In the Cutbank Ridge portion of our Montney, which is on the – in B.C., that plan really hasn't changed in a couple of years and really won't change. The only thing that's happening is it's becoming more and more capital efficient.
I mean, we're now drilling those wells for about $5 million, which is really, really impressive. In the Alberta side – and this is a differentiation Mike talked about, Pipestone – these are incredible wells.
We're talking 1,500 to 1,600 barrels a day of condensate, plus around 2.5 million. And this is a portion of the play we're just now proving up.
And it is an area where we have some ability to deploy new capital. We've been working on how to do that while minimizing facility spend.
So we're working on that now. And that's one of the places, whether it's later this year as we go to next year, which I would expect us to apply more capital to.
And the new royalty framework here in Alberta actually makes that competitive. Because south of the border, we have a lot of flexibility in the Permian.
We've run a lot more rigs than we're running today, we have the acreage to do that, and I think we have the techniques to do it. So the only place we really wouldn't anticipate doing it is largely the Montney, and a little bit in the Duvernay.
We have a – Mike mentioned the new gas plant, which we said was going to come on by the end of the first quarter, and it did. And we have some additional capacity there we could fill in.
But I think largely we'd be looking to three areas today, it'd be the Pipestone, Alberta, Montney; it'd be the Permian and the Eagle Ford, are the more likely places to attract new capital.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Great. I appreciate the detail.
And then one just high-level one on the remaining trajectory throughout the year. If you look at kind of the low end of the low end of the budget, I guess about 40%'s been spent in Q1.
Can you just kind of talk about how that, the rest of the budget could be spent throughout the year, just based on your current drilling plans?
Douglas James Suttles - President, Chief Executive Officer & Director
You know the shape isn't a whole lot different than last year, and part of it's because of the commodity price environment. So it ramps down through the year, but obviously we can ramp that back up if market conditions changed.
And I would expect us, if we started to do that thing, to protect at least some of that capital and cash flow with our hedging program, as you've seen us do in the past. But capital comes down through the first couple of quarters and largely stabilizes in the second half of the year, is what it looks like.
Largely the activity drop that – when we announced the revised budget in February has largely been done. There's a bit of activity falling off a little later in the year, but the big chunk happened here in the first quarter.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Thank you.
Operator
Thank you. Our next question is from David Meats with Morningstar.
Please go ahead.
David Meats - Morningstar, Inc. (Research)
Yeah. Thanks, guys.
I just wanted to ask, you mentioned a few work force reductions last year and I think on this call as well, and I was just wondering how much that impacts your ability to grow in a better commodity price environment?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah, David. Good – another good question.
The – we actually put a lot of effort in this. So when we did our downsizing in March, one of the things we did is tried to create the capacity to grow in how we did that.
So we did two things which are a little different. One is, we did a big redeployment program where we displaced contractors and some service providers with staff, particularly in the field.
And there are two benefits to us from doing that. Number one is it allows us to hold onto this talent, because we would expect our capital budget to be higher in the future than it is this year.
So these are a lot of our engineers and even geoscientists. The second thing is, clearly it'll help their development.
They'll learn new skills. They'll be more valuable employees going forward.
The second thing we actually did was introduced a sabbatical program, where people could take time off without pay and we'd have the ability to bring them back. And the worst case for them is if we didn't bring them back, they would get their severance at that point.
We protected around 80 people in doing that, so that's about 4% of the work force. But in particular, it's particularly meaningful because a lot of these staff are tied to our capital activity.
So we've tried to create some flexibility in the way we're managing the work force to do that. In addition, this focused portfolio concept we had, and the things Mike talked about with our pad development schemes, makes it a bit easier for us to grow activity without having to proportionally grow staffing.
David Meats - Morningstar, Inc. (Research)
Okay. That's really good color.
And just one more from me. On the – you guys reported some, I guess, more impressive than expected well costs, particularly in the Permian, and it sounds like part of that is technical improvements with the things you were doing, 14-well pads and all that kind of stuff you were talking about.
I was wondering how much of your acreage can physically be developed that way?
Douglas James Suttles - President, Chief Executive Officer & Director
Yeah. Quite a bit of it, actually.
And we haven't talked about a lot of the details, but as we do normally in every play, we continue to work to core it up, to make it more contiguous. So we've done small deals to add little pieces to it, and we've also done some swaps to continue to core it up, because I think if you've watched our history, we tend to like to drill big pads with long laterals.
And quite a bit of the core of our acreage allows us to do that. Then the other thing, don't forget, this is stacked pay, and we haven't – even in our 14-well pad, we're only accessing three horizons on that pad.
David Meats - Morningstar, Inc. (Research)
So it sounds like the contiguous nature of the acreage, that's the main driver, more so than anything geological?
Douglas James Suttles - President, Chief Executive Officer & Director
Well, the acreage is in the core of the play, which is the stacked pay component. So if you look at what we're doing this year, we're focusing a lot of our work in Martin County and Lower Spraberry.
We're actually drilling some wells there right now, which you'll see results from. And then as you go south to Midland County, it's largely been in the Wolfcamp, but we still have a lot of other zones.
So it's a combination of the way the acreage sits, where it sits, the stacked pay piece, and then this continual effort to core it up. I should say, there's one other thing which I don't think we even highlighted on the call yet, but we further reduced the requirement for vertical drilling in our Permian position by another 12 wells through the first quarter.
So we've massively reduced this program by working with the mineral owners in minimizing the amount of capital we have to put to that program. It's been a great effort by the team.
David Meats - Morningstar, Inc. (Research)
All right. Thanks a lot, I appreciate it.
Operator
Thank you. At this time, we have completed the question-and-answer session.
I will turn the call back to Mr. McCracken.
Brendan McCracken - Vice President, Investor Relations
As a reminder, Encana's Annual Meeting of Shareholders will be held this morning at 10:00 a.m. Mountain Time at the BMO Center in Calgary.
A live audio webcast of the meeting as well as presentation slides will be available on our website. Thank you, ladies and gentlemen.
Our call is now complete.
Operator
Thank you. The conference has now ended.
Please disconnect your lines at this time, and we thank you for your participation.