Ovintiv Inc. (OVV) Q2 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Second 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. [Operator Instructions]. For the 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 Brendan McCracken, Vice President of Investor Relations. Please go ahead, Mr. McCracken.

Thank you, operator, and welcome, everyone, to our second quarter 2015 results conference call. This call is being webcast and the slides are available on our Web site at encana.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 after royalties, unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will provide the highlights of our second quarter results. Mike McAllister, our COO, will then provide an update on our recent operating activities. And Sherri Brillon, our CFO, will discuss Encana's financial results before we open the call up for Q&A. I will now turn the call over to Doug Suttles.

Thanks, Brendan, and thanks, everyone, for joining us this morning. Our second quarter results reflect important progress in the execution of our strategy. After significant portfolio high grading last year, we are now driving organic growth. Following seven consecutive quarters of liquids growth since launching our strategy, we continue to improve well performance, lower cost and increased well inventory in our four strategic assets; the Permian, Eagle Ford, Duvernay and Montney. We exited the second quarter with significant operational momentum and we expect to accelerate liquids growth through the second half of this year. We are on track to achieve $375 million of operating and capital cost efficiencies by year-end, and we believe that about two-thirds of these savings will be sustainable in a higher price environment. During the quarter, we used the net proceeds from our March equity issuance along with cash on hand to retire approximately $1.3 billion of long-term debt. This brings our total debt redemption since the launch of our strategy in November of 2013 to about $2.3 billion. We are proactively managing the business through the current environment and we continue to drive efficiency through innovation and capture opportunities to further reduce costs, improve cash flow and strengthen the balance sheet. Like others, we did see some impact in the quarter from adverse weather and flooding in Texas and third party facility constraints and pipeline outages impacted our Montney operations. These issues are largely behind us, as we are well on our way to ramping up production in the Permian and Eagle Ford where we expect to bring on approximately 40 wells in July and an additional 36 wells over the balance of the third quarter. We remain on track to meet our fourth quarter production target of 270,000 barrels of oil equivalent per day from our four strategic assets. We expect that liquids production from these assets will be up more than 50% when compared to the fourth quarter of 2014. Consistent with our strategy to transition the portfolio towards higher margin production, we expect our four strategic assets will contribute about 65% of total production in the fourth quarter. These four assets are located in the core of four of the highest margin and return basins in North America and they continue to deliver competitive returns through the current commodity price environment. For the year, we expect the Permian, Eagle Ford and Duvernay to deliver a weighted average operating margin of about $26 per barrel of oil equivalent with the Montney delivering an operating margin of around $1.15 per Mcfe. These assets are also generating strong returns at current prices. Across the four assets, we expect to deliver rates of return greater than 30% using a $50 WTI oil price and a $3 per MMBtu NYMEX gas price. Through our relentless focus on innovation, we continue to seize opportunities to enhance our performance. We plan to continue to focus our remaining 2015 capital to these four assets. I will now turn the call over to Mike McAllister who will talk about some of our very encouraging operating results we delivered during the quarter. You will also find additional assets specific information in our updated corporate presentation that will be at our Web site shortly. Mike?

Thank you, Doug. Let’s start with the Permian. We are very pleased with the progress to-date. We have moved from being an early adapter to a lead innovator, from above ground and below ground. For example, in Q2, our fracs were 75% larger than the average from 13 other Midland basin operators. We are evaluating the impact of these completions on well performance and returns. We are also piloting managed pressure flow-backs to test the impact on oil IP180 and oil EUR, and therefore returns. Also, we have discussed on our last call we had introduced simultaneous drilling and completion operations on our horizontal pads. This has reduced our spud to initial production times by approximately 30 days. This lowers cost and speeds the time to positive cash flow, therefore improving returns. We’ve done this while overcoming the challenges associated with the new asset and unusual weather conditions in January and May. In Q2, we ran six horizontal and six vertical rigs placing Encana as the most active operator in the Midland basin. We rig released 23 net horizontal and 29 net vertical wells. The horizontals are targeted at the Wolfcamp and Spraberry zones in Martin, Midland, Upton, Glasscock and Howard counties. Vertical [ph] wells include TXL and Davidson wells, which are on production at 1,300 Boe per day and 1,100 Boe per day, respectively. We are very focused on efficiencies. Our horizontal rig fleet has now been fully converted to fit-for-purpose rigs. The multi-well pads have dropped well cost by 25%. Our pacesetter well is now a 15-day drill. We are targeting $6.4 million drilling and completion costs. This includes approximately $600,000 of incremental costs associated with higher intensity completions. As we learn more on how these wells perform, we will refine the completions to deliver better returns. We have recently entered into an oil gathering agreement and we expect that about half of our production will be tighten by year-end. By enhancing the reliability of our production and significantly reducing trucking, our operating margins will improve by up to $2 per barrel. Production growth will accelerate in the second half of 2015 starting with 53 wells coming on production in Q3. July month to-date, we now have 16 horizontal wells on production. This year’s drilling program is evaluating our 5,000 well inventory across all five countries where we hold [indiscernible] and Midland basin. Results to-date support our type curve assumption. We currently have four horizontal and five vertical rigs working in the Permian. We plan to keep drilling activity [Technical Difficulty] for the rest of the year. As I mentioned previously, we have been managing the flowing pressure of our wells. Our objective is to maintain flowing pressure above bubble point by restricting production rates. We are evaluating the impact of this pressure management on our oil EUR and our oil IP180 rigs to maximize value. Generally speaking, we are drawing our wells down half as fast as it was being done by our previous operator. With another 86 net wells expected to come on production in the second half, we expect Permian production to average over 50,000 Boe per day in Q4. It’s now been one year since we acquired our position in the Eagle Ford, and we are very excited about how our team is drilling the value of the asset. For example, by making significant improvements to our artificial lift systems, the decline rate on our base production has been reduced by about half of what we expected at the time of the acquisition. We also made great progress in reducing our D&C costs by almost 30%. When we acquired the position, D&C costs were $7.7 million per well. In Q2, we averaged $6.2 million. Costs are expected to fall further to $5.6 million in the second half of this year. In fact, we have just recently completed [indiscernible] A-5 well at a cost of just $5 million. Although this was a little shorter lateral at 4,320 feet, we are very pleased with this result. We are currently running two rigs in the Eagle Ford and expect to continue at this level through the second half of this year. In the Kenedy area, we have just brought on stream a Patton Trust South facility, which increases our processing capacity in the area by about 25,000 Boe per day. With our PTS facility now ramping up, we expect our total Eagle Ford production will be exceeding 50,000 Boe a day shortly. This represents a 15% increase, I should say, from when we began [indiscernible] program in Q3 2014. We’ve also been doing a lot of work to expand our well inventory in the Eagle Ford. A year ago, we pegged our well inventory at about 400 wells. Since then we’ve drilled over 75 horizontal wells. Today with our new understanding of the Graben and assuming average well spacing of 30 to 40 acres, our undrilled well inventory stands at over 600 locations. This is a 70% increase since we acquired the asset. We expect our well inventory to further increase once we get a better working knowledge of the Upper Eagle Ford. In the first quarter conference call, we indicated that Graben had 60% improvement in 180-day production rates with a corresponding doubling of EURs to about 500,000 Boe per well. Results from our Graben wells have continued to impress with the best wells so far peaking at over 1,300 Boe per day. We continue to dramatically reduce our costs in Duvernay. For the first time, our D&C costs are now below $11 million per well. We are now targeting below $10 million per well on our next pad. We are very excited about the impressive well performance we’ve seen from our multi-well pads. Our 16-11 well is on production at 2,000 barrels per day of condensate and 11.5 million a day of rich gas after 27 days of production. Our first four wells from our latest pads have been brought on stream at an average of 2,700 Boe per day, which is made up of 1,340 barrels a day of condensate and 8.2 million a day of rich gas. There are seven more wells to bring on from these two pads. We should also note that these production rates are producing at over 3,000 PSI flowing pressure. These two wells are over and above the results that were featured in a recent independent research report that pegged our Duvernay supply cost at $46 a barrel. We’ve successfully repeated our dual-frac spread program. By operating two frac spreads on the same multi-well pad, we’re able to maximize run time and pump nearly 3x [Technical Difficulty] per day than we can with a single spread. This innovation has resulted in approximately $700,000 of savings per well. Furthermore, we were able to reduce our spud to initial production time by about a month. The start-up of a water infrastructure has also enabled us to reduce well costs by over $1 million per well and improve our operating margin by about $2 per Boe. We have now identified about 1,100 locations in Simonette alone. Our drilling program this year focused on very rich condensate window. These wells have condensate gas ratios between 150 to 250 barrels per million and represent 40% of our total inventory. Similar to other areas, we are working hard to improve well performance and we’re seeing outstanding results. The graph on the lower left shows the average performance of eight wells that came on production in Q2. For these eight wells, production rates ramped up to an average of 1,000 barrels per day of condensate and 6 million a day of rich gas. In addition, we have four recent wells from the 12, 6 and 14 to 20 pads that have higher intensity completions. These wells are outperforming type curve expectations. The 16-11 well is included in this group, and as I mentioned earlier is producing at 3,900 Boe per day after almost 30 days. The condensate rates for the other three wells in the group are 1,500 barrels per day, 1,000 barrels per day and 800 barrels per day. Each of these wells is flowing at greater than 3,000 PSI. In the current oil and gas price environment, we’re frequently asked if our Duvernay operations are commercial. These results prove they clearly are. The unlevered return on the 16-11 well at today’s prices is 50%. With improvement on cost and well performance combined with the favorable 5% royalty rate in Duvernay, we are excited about the returns we have generated. In addition to the strong unlevered economics, we would expect to see joint venture carry continue through the end of 2016. We’re pleased to report on a new condensate rich area on the Montney in an area we call Dawson South. Here we are seeing Montney wells in the heart of our Cutbank lands producing 300 to 400 barrels a day of condensate and 10 million a day of gas. One of the first wells we drilled in Dawson South has produced at a restricted rate of 300 barrels a day of condensate and 8 million a day of gas for over 200 days. As a reminder, prices for both Montney and Duvernay condensate enjoy [Technical Difficulty] prices. Between Dawson South and our condensate rich lands in Tower area, we now have greater than 1,100 condensate rich locations in Cutbank. When combined with our Alberta condensate rich inventory, we now have more than 1,500 undrilled condensate rich locations in the Montney. Our current D&C target is $6 million. In Q2, our average base [ph] costs have been reduced by 20% compared to Q1. We have continued to see efficiencies and set a new record this quarter in our Tower area with the spud to release of just nine days. All five wells in the pad were 10 days or less spud-to-rig release. As you’ll see on the next slide, we continue to optimize our completion designs and we are seeing 33% uplift in IP and EUR. The 15-27 compressor station came on production ahead of schedule and under budget. This station, which we operate, is part of our midstream arrangement with Veresen. 15-27 is designed to handle 200 million a day of gas and 2,000 barrels a day of condensate. As Doug alluded to, we have experienced some curtailment and restrictions on the TCPL system. Currently, we are experiencing no curtailments. For the remainder of the year, we anticipate there may be intermittent disruptions. We commonly hear our Montney position describes a dry gas asset. In reality, we have built a large exposure to condensate in the asset and now have about 1,500 condensate rich locations. 1,000 of these locations are wells with greater than 40 barrels per million of free condensate. At 10 million a day, this equates to 400 barrels a day of condensate. Our total undrilled well inventory in Montney now stands at 5,000 locations. The significant increase in liquids rich wells in the Montney inventory gives us a new option in our portfolio for condensate growth from Tower, Dawson and Pipestone. Various reports published by investment banks indicate we have drilled some of the best condensate-rich and gas wells in Canada this year. In 2014, we reduced our cluster spacing to 80 feet and realized a 70% uplift in well productivity compared to our original slickwater design. This year, the team is focused on doubling proppant concentration from 1,000 to 2,000 pounds per foot. By doubling the tonnage, we expect an additional 33% increase in overall well productivity. Our latest completions have resulted in a restricted gas rate flat at 10 million a day for over 200 days. Our target is to increase the capability of our well sites to flow 50 million a day. These well results are generating very competitive returns on an unlevered basis. In addition, we expect the joint venture partnership carry to continue through 2019. In Pipestone, we drilled two oil wells that came on production in the quarter at over 1,000 barrels per day. As well, we have notable results in our carry [ph] program at San Juan. We had six transverse wells come on production at 700 barrels a day, which is 100% improvement over our original oblique well design. I’ll now turn the call over to Sherri to discuss our financial results.

Thanks, Mike, and good morning, everyone. As Mike illustrated, we delivered solid results in the second quarter. We continue to build momentum in our operations and expect to accelerate liquids production growth through the second half of the year. We have delivered significant year-over-year growth in oil and NGL volumes with average production of about 127,000 barrels per day during the quarter, an increase of 87% compared to the second quarter of 2014 and about 5% higher than our Q1 volumes. Natural gas volumes were down about 38% year-over-year largely due to the impact of our seasonal operating strategy at Deep Panuke as well as divestitures, the TCPL outages, third party facility turnaround and natural declines. Q2 cash flow of $181 million decline by about $350 million compared to the first quarter of this year. Approximately half of that decline can be attributed to our seasonal operating strategy at Deep Panuke. The other half can be attributed to our 165 million cash outlay associated with the early debt redemption. This is expected to save us about $200 million in future interest expense. During the quarter, we received $140 million from net divestitures, which brings our year-to-date net divestiture proceeds to $978 million. This further simplifies our business and the assets sold had very little impact on both production and cash flow. We updated our hedging program during the quarter layering on 2016 oil hedges. So now we have roughly 38,000 barrels per day at about $63 per barrel and slightly increasing our 2015 oil hedges to roughly 59,000 barrels per day at about $62 per barrel. Our natural gas hedge position remains unchanged. Similar to Q1, we recorded a 1.3 billion after-tax impairment charge that impacted our second quarter net earnings. The ceiling test impairment primarily resulted from the decline in 12 months average trailing commodity prices. This is non-cash charge. It does not reflect the fair value of the assets. We remain on track to achieve our 2015 guidance and expect cash flow to come in at the mid to high end of the $1.4 billion to $1.6 billion range. When we combined our expected cash flow with the net divestiture proceeds we have already received this year, we expect cash inflows to exceed our planned capital expenditures and dividends by about $100 million. As we indicated last quarter, our plan was to invest roughly two-thirds of our capital budget in the first half of the year. Our Q2 year-to-date spending of almost $1.5 billion was in line with our expectations. We remain very disciplined and focused to approach capital allocation. Maintaining financial flexibility is very important to us. If we have additional finance capacity in the second half of the year, strengthening our balance sheet would be our first priority. We would then consider accelerating activity in our four strategic assets depending on market conditions. The only change to our guidance this quarter is the reduction of our DD&A rates reflecting the impact of the impairment charge incurred during the quarter. If any additional impairment charges are incurred throughout the remaining – remainder of the year, we expect our DD&A rate to be further reduced. Our focus on efficiency is a key part of building a high-performing and cost efficient company that is resilient through the price cycle. We are delivering on the efficiency in costs reduction targets that are build into our guidance. This includes a 15% improvement or about $300 million of capital cost efficiencies plus $75 million of direct operating cost savings. We expect that two-thirds of the capital savings are sustainable going forward even if commodity prices rise. These sustainable savings rise from the changes to how we drill, complete and tie in our wells. For example, across the Permian, Eagle Ford and Duvernay, we will be self-sourcing proppant chemicals and managing the logistics in-house. Our work with bits, motors and casing design continues to drop days from our drilling programs. Our completion engineers continue to reduce maintenance times to drop days from our competition programs. In the Permian and Duvernay, our simultaneous operations reduced the number of days on location. We have also recently completed a corporate restructuring to continue to align our structure with our more focused portfolio and disciplined capital investment program. Since we launched our strategy in November of 2013, we have reduced our staff count by 1,400 people and our overhead costs have been reduced by a third or $300 million per year. Going forward, we expect that our clean G&A, excluding items such as restructuring costs and long-term incentive costs will average around $60 million per quarter. Since 2013, our average interest expense is down by 100 basis points due to our net repayments and implementation of our $2 billion U.S. commercial paper program. As a result, we have reduced our interest expense on debt by a third or $150 million per year. Based on current debt levels, we expect that our interest expense on debt will average about $75 million per quarter. Our commitment to maximize the efficiencies has set us up well as we begin to plan for next year. When we combine durable cost reductions with the increased focus in capital allocation and a leaner workforce, the dollars we spend in 2016 should generate higher returns. Our debt position improved significantly during the quarter with the repayment of $1.3 billion of long-term debt. We also recently amended and extended our revolving bank credit facility of $4.5 billion, which are committed until July of 2020. We remain and expect to remain in compliance with the financial covenant in our credit agreements, which requires our debt to adjusted capitalization to be less than 60%. As of June 30, this ratio came in well below that requirement at 28%. Maintaining an investment grade credit rating is an important aspect of our strategy. We have been very proactive in our efforts to increase liquidity and financial flexibility, and we believe that we are well positioned for 2016 and beyond. Our actions have strengthened our balance sheet, enhanced our credit metrics and provided greater flexibility for the execution of our strategy. I’ll now turn the call back to Doug.

Thanks, Sherri. As we look forward to the rest of the year, we remain intensely focused on operational execution and on capturing further efficiencies. We continue to drill better wells, capture sustainable cost reductions and increase the well inventory in our four strategic assets. Our Montney is a low-cost prolific play with growing liquids volumes. Our Duvernay is combining dramatic cost reductions and impressive well performance. Our Eagle Ford inventory has almost doubled as we improve efficiency. And our Permian is demonstrating strong well performance as cost drop and production growth accelerates. Our frontend loaded capital program has positioned us to significantly accelerate liquids growth in the second half of 2015, and we remain on track to deliver our fourth quarter production target of 270,000 Boe per day from the Permian, Eagle Ford, Duvernay and Montney combined. The quality of these four assets along with our proven technical expertise is generating strong margins and robust returns. This makes us competitive at all points in the commodity price cycle. We continue to successfully execute and enhance our strategy. Our second quarter results highlight the quality of our portfolio, the discipline of our capital program and our commitment to maintaining a solid balance sheet. Thank you for the time and our team is now ready to take any of your questions.

[Operator Instructions]. Greg Pardy of RBC Capital Markets, your line is open.

Thanks. Good morning. I guess a couple of questions. The first one is just in terms of your targeted D&C costs that you’re outlining in your slide deck. Is your expectation that you would be there by year-end or before?

Yes, Greg, I’ll just make a couple of comments and hand it over to Mike. I think first in some cases, we’re already delivering, if you will, our pacesetter wells are already hitting our target cost but in all cases we expect to be delivering average cost in those range by the time we reach the end of the year.

Yes, absolutely, Doug. Hi, Greg. I mean every one of our plays, we actually is have an example pacesetter well that’s actually already hit those target costs, and the teams are working on an idea in terms of how to drive those costs down further. We have a track record of performance on driving our drilling and completion costs down, and feel really confident about that.

Okay. Thanks for that. I guess the second question is the big four plays, as you mentioned, about 270,000 Boe a day. It is substantially higher obviously than where you were in 2Q. Can you just walk us through what needs to happen, I guess, particularly in the third quarter to put you in good stead to meet those numbers?

Yes, Greg. If you look at the shape of our program this year, we had a very heavily frontend loaded capital program and that’s very obvious now that you see our first two quarters of capital. That was really driven by two factors. One is, is we actually closed down our capital program and all of our assets other than those four. And that capital represented about 20% of our total capital, and largely those programs are now stopped with very few exceptions. The second is, is the Permian a great example. I think we entered the year running about six horizontal rigs and I think as Mike already mentioned, we’re running four and anticipate running that through the end of the year. So that’s the shape of the capital program. The production ramp up, particularly in the Permian and the Eagle Ford is second half loaded largely because of two things. One is, is we’ve gone to multi-well pads in the Permian and because of that obviously it takes a little longer to bring the wells on production, because in general we’re drilling four well pads. We have to drill the four wells and complete them. We have gone to this simultaneous operation to speed that process up. The second thing we’ve done is, I think Mike mentioned this as well in his comments, we’re pumping lot larger fracs even than we originally planned when we bought the asset in November of last year. And those wells take about 60 days to clean up, 45 to 60 days to get the peak grade. But as Mike mentioned, we’ve got a big ramp up in well count underway right now. So the wells he talked about we drilled in the quarter are largely just now coming on production. And then in the Eagle Ford, we had to expand one of our batteries quite significantly, Mike mentioned this, Patton Trust South. That actually started up on the 13th of July and that’s a massive facility; 25,000 Boe a day and I think – Mike, maybe you can clarify – I think we’re over half that full rate now in that new facility.

Yes, you bet. Yes, we have 17 new wells, 32 wells in total. We have 31 of those 32 wells on production and ramping up. So we’re in pretty good shape. In fact, in the Eagle Ford right now, on the total we’re just under 50,000 Boe per day in production.

Currently, okay. And you wouldn’t have a current production number, like the cost to the big four, would you?

At the top of my head, I think the Permian is running around 40,000 Boe a day just now and I would have to – we can try and follow up the other two, the Duvernay and the Montney.

But I think as Mike mentioned, 2Q in the Montney was impacted by a third party gas plant Turner and they took longer than they thought and then the TCPL NEB program. The good news is there those curtailments have recently been lifted and we’re optimistic we’ll have less impact in the second half of the year.

That’s great. Thanks, all.

Your next question comes from Mike Dunn of FirstEnergy. Your line is now open.

Good morning, everyone. A couple questions on the Eagle Ford and forgive me if they’re a little bit ignorant, but the Graben area, is there multi-stack potential there? I don’t think there’s Austin Chalk in that area, but is that just lower Eagle Ford potential in that area? And then maybe just talk about what you’ve included, if any, for Austin Chalk wells in the I guess over 600 well inventory total in Eagle Ford? Thanks.

Yes, Mike, I think that – when we refer to the Graben area, it’s in the oil window. For instance, this Patton Trust South that we’ve been doing a lot of work is in the gas condensate window. But in the Graben area, we actually – when we’re talking about our current inventory increase, that’s really just driven by one [indiscernible] leaving that Graben and those Graben wells are going to be economic into tighter spacing. We’re planning to test the Upper Eagle Ford in the fourth quarter of this year, but we actually are counting – our inventory doesn’t count that and we have no Austin Chalk wells in that inventory. So both the Upper Eagle Ford and the Austin Chalk are both upside.

Okay. And then in the gas condensate window, Doug, I’m assuming it’s sort of on trend with what other guys have in drilling Austin Chalk wells. Is that fair to say?

Yes, and Upper Eagle Ford wells. Some of our offset operators as you’ve seen have been testing both the Austin Chalk and the Upper Eagle Ford in that area.

Okay, so no immediate plans for you to test Austin Chalk?

Not right now, not this year. Right now our plans are to test the Eagle Ford this year. We’re evaluating the Austin Chalk and we’ll see about whether we include that next year.

Great. That’s all from me. Thanks.

Your next question comes from Mike Rimell of UBS. Your line is now open.

Hi, guys. Just maybe a quick one on the Permian. I wondering if you guys still think you’re on track to meet the low end of guidance there? Obviously, we have the first two quarters in hand and you’ve talked about before at 50,000. It’s difficult to get the low end if I do the math there.

Yes, Mike. I think where we’re at is for the full year, right, we’re a little behind what we thought we were going to be largely because of doing the multi-well pads and the bigger fracs. But we still think – if you recall, we still believe we’ll hit our 50,000 Boe a day number. Just as a reminder, when we bought the asset it was producing 28,000 Boe a day and we’ve now got it at 40 and we think our 4Q average will be at least 50. And this is tricky space here. We’re trying to do this stuff right. We’re actually doing managed pressure flow backs on our wells, so we’re not trying to get the biggest number on the wall. We’re trying to get the best return from the well. And that means how do we make sure we get the maximum AUR and the best rate over the first six months and not only the first 30 or 60 days. The other thing I’ll just tell you is when we inherited that asset, a number of basic processing systems weren’t in place. And we’ve had to put those in place and those have taken a bit more time than we anticipated, a bit more of our management time. These are little things like invoice management and production accounting and basic field operations were quite a bit of improvement, probably more so than we thought when we originally purchased it.

Fair enough. Thanks. Obviously, continuously changing but fair to say you think you got your hands around it now.

Yes, we do. One of these things when we took it over obviously, it was about six months after making our Eagle Ford purchase, we probably went into the Permian one thinking what we could jump in straightaway is, is optimizing development plans and we had a bit more blocking and tackling to put in place in the existing production operations. That said, I’ve been really impressed with Mike and the team on – I think we’re already at the frontend of innovation out there. We’ve already tested 4,000 pounds per foot fracs. We’re trying to see where the optimum is. Clearly, in some parts of our portfolio, bigger is better. Here we need to find out, as Mike mentioned, we’re gathering the data. We’re doing these multi-well pads. Mike mentioned this. You guys shouldn’t overlook at this oil gathering system. We’ve now put a contract in place too. We’ll add about $2 a barrel to our margin, and it will mean things like the weather impacts we saw in January and May should have much less impact in the future, because instead of fracing oil we’ll be gathering it by pipe. So I think we’re trying to do this right. We see this as a critically important asset to the company in the future and it’s early days. But I think we’re on track to hit our 50,000 barrel target.

Great. Thanks very much. And then just quickly on potential asset sales, obviously four to seven core assets, I count 15. Fair to say you’re still actively exploring a few options there?

Yes, Mike, you know my standard answer here but we’ve been pretty clear I think all year that we think a tighter portfolio is the more efficient portfolio. We clearly have made massive change in it. We’re really pleased with these four strategic assets. We also at the time we launched the strategy held some optionality in our portfolio. You can’t hold that forever. So I think directionally, tighter is the right thing to do but we actually never think it’s wise to announce these things either specific targets or asset sales. Clearly, if we do something we’ll announce it at the time we do it. And I think Sherri indicated if we did make a significant investment, how we would look at these to the proceeds.

Excellent. Thanks. And then last one from me, you talk about a base level of capital spending of about $2 billion required within the company. As we look forward to next year, should we think about something similar do you think you can bring that down?

Well, I think it’s a great question, Mike, because what we said is, is the core to the value creation we’re trying to deliver here is what was 200,000 barrels a day equivalent in the fourth quarter of last year from our four strategic assets going to 270 is to keep that growing. And what we said is, we’d like to, if you will, defend a minimum $2 billion capital program. We don’t have to do that, but would like to because that keeps that number growing. We’re starting to look pretty hard at '16 and one of the things that’s encouraging us is we think we’re going to end 4Q very strong, particularly on liquids production, which means we’ll enter '16 strong. The second thing is, as Mike went through all the wells, our costs are down substantially and typically more than 20%, which means our capital will be more productive. And then the third thing is that 20% or so of our capital we spent outside this year, I would be surprised if it’s anywhere near that large next year. So all of those things should allow us to generate a capital program next year even in a commodity price similar to today if we keep those four.

Great stuff. Thanks very much.

Your next question comes from Benny Wong of Morgan Stanley. Your line is now open.

Thanks. Can you provide some color of where you think the Permian will exit this year, and maybe comment on the momentum that you guys are expecting on the play into '16?

Yes, Benny, as we mentioned, our 4Q average production we’re saying we should achieve 50,000 Boe a day or greater in the fourth quarter. That’s our exit rate we’re anticipating. And largely, as Mike mentioned, that ramp up is happening right now as we’re bringing on new wells. A little bit early to say exactly how we’ll distribute capital in '16 even though I suspect the Permian will get of the four the largest component next year.

Thanks. And just in the Permian just want to get a sense of how many lower Spraberry wells you’ve drilled? It is just at two that’s in your presentation. And even if it is, can you give us some initial thoughts on horizon, how it compares to your expectation and to other formations as well?

Yes, it’s just the two lower Spraberry that we’ve drilled so far although we’re very encouraged by the results we’re seeing into Martin County. So we’ll continue to focus on that. I don’t have the number in terms of the numbers we’re planning on drilling here between now and the end of the year. But yes, really encouraging results on the lower Spraberry.

Great. Thanks.

Your next question comes from Stephen Richardson of Evercore ISI. Your line is now open.

Hello.

Yes.

Hi. Doug, I was wondering if I could just go back to the 2016 question about capital, I appreciate the service cost is down quite a bit. Can you continue as you wound down the rest of the portfolio outside of the big four in terms of capital, do we just assume that you continue to starve the rest of the portfolio of capital into '16 in a $50 to $60 world? Is that really the right assumption or is there some point where capital needs to come back?

Steve, I think that what’s really changed after U.S. Thanksgiving Day last fall and the reset on oil price was when we look at our portfolio, clearly we have a massive inventory of what we think are very high quality options in the four. In fact, I think our inventories now are 11,000 wells in those four assets, so it’s a pretty significant number. So when you combine that with our strong belief that a tighter portfolio, we don’t want to be a single-play company. We don’t believe that creates the best value for our shareholders, but we also think a limited one is more efficient. And as Sherri outlined in our cost piece, since we started in the fall of '13, we’ve reduced our workforce by over 1,400 people by almost a third while maintaining similar levels of activity and largely that’s being through a tighter portfolio. So clearly what we have to decide is where those assets fit and what point they compete. That said, we’ve had some really interesting results before we brought our San Juan program to a close we made some changes to how we were drilling those wells and we coupled the IP30s out there. So we have to consider those things as we think about the portfolio going forward. But right now in a low commodity price environment, we got our capital very focused on the four. We think that capital allocation is core and as we’ve talked about, we do it centrally and we do it with what I think is incredible discipline.

I appreciate that. And so I guess the other question was, if I look at what is obviously a pretty challenged environment for dry natural gas assets and negative netbacks across a lot of the legacy gas portfolio, and I appreciate Sherri’s comments about potential for further TCPL disruption for the rest of the year. Do we see the potential for beyond [ph] shut-ins in the second half of the program?

At this point, I don’t think so, not at today’s gas prices. We have – our operating margins are all positive across our gas portfolio. And I should say our gas production is dominated by the Montney and at a $3 NYMEX price, which roughly translates to about $2.40 AECO price, our margin’s $1.15 per Mcfe. And by the way, if you roll in what Mike talked about with the higher liquids yields, we’re getting and as we bring those wells in that margin we think can grow by more by more than 50% with no increase in gas price. And we see that as very competitive. And I think if you model out what’s in our deck with the EURs, the flow rates we’re seeing [indiscernible], you’ll see those returns at this AECO price actually quite attractive.

Okay. Thank you very much.

Your next question comes from Jeffrey Campbell of Tuohy Brothers. Your line is now open.

Good morning. First question, in the last quarter it looked like the Permian CapEx rose about 50% and the other big three saw a declining investment quarter-over-quarter. Can you expand on the drivers behind these decisions and what this spend might look in the second half?

Yes, Jeff, good question. Right now as we literally sit here today, we’re actually expending capital in three assets right now; the Permian, the Eagle Ford and the Duvernay. We’ve largely completed our Montney program for the year. We have a bit more work to do in the Duvernay. But largely through the balance of the year most of the capital is being spent in the Permian and the Eagle Ford. Just as an example, I think at the moment all of our rigs that we’re running are currently in the Permian and the Eagle Ford today. Later in the year we anticipate bringing back several more rigs in the Duvernay.

Great. Second question was going back to the managed price regime that you’re doing, are you doing that in all your Permian counties and the EUR enhancements that that may bring, are those already baked into the EUR guidance that you have on Slide 6?

Yes, I’ll let Mike pick up the detail in there, but this is one of these – we’ve done this in some of our plays. The DJ is probably the one we’ve had the most experience with. And we actually do believe that staying above bubble point pressure should improve – the most important part of that EUR is the oil and that’s what we’re focused in on. It’s how do we maximize the oil EUR not just the Boe, and we think that drives it. But Mike can probably fill you in across the five counties we operate in.

Yes, we’re using the same operating practice across all five counties. Actually, we look at this across all of our plays making sure that we’re taking – managing our drawdown pressures to not go below bubble point too early and thus changing the relative permeability in the new wellbore. The point of this – the reason we’re doing this is to maximize our oil production and not break through to gas too early. And we’re in the evaluation phase right now in the Permian and we’re going to see how that works out and make it basically to drive the maximum value for the asset.

Jeff, I think the impact on the EURs, we just need to wait and see. In some of our plays we’ve seen it improve but in some – and make sure you recover what you forecasted. It’s a little early but we’re clearly watching that. And as Mike indicated, we’ve talked about this for several quarters. We actually think one of the core measures to look at on all of our wells is kind of IP180. We have to be real careful. I know IP30 sort of grab a headline but what really drives the economics and returns is what’s the maximum rate you conceive in that first one or two years when you really dominate your returns.

And if I understood what you were just saying correctly, it might end up being that the results of the managed program is perhaps a better mix not necessarily a better absolute EUR?

It could be that and it could be just a larger EUR, it could be both. But clearly what we want to make sure of is a little over – in the Permian, a little over 80% of our EUR is actually liquids and that’s the part we want to make sure we optimize.

And last question that I wanted to ask was could you just provide some further color on Pipestone, what’s the oil gravity, what’s the go-forward drilling plan based on the two recent successes? I know you’re not running rigs up there now, but does this encourage you to do more in the future and kind of what does that look like?

Yes, we’re really encouraged what we’ve seen in Pipestone. We have 100 to 200 locations that we’ve identified in the oil window there, as well as there’s IP-ing [ph] at 1,000 barrels per day. The gravities are in kind of the mid-40s, API gravity. And we’re actually constrained right now with respect to facilities, so we’re basically drilling to fill as we look at our program going forward and also looking at optimization of facilities with respect to it.

Okay, great. Thanks very much.

Your next question comes from Nick Lupick of AltaCorp Capital. Your line is now open.

Thanks, guys. Two quick questions from me. First on the Eagle Ford, how many of your 600 well inventory is in the Graben? And the second question was about the Montney and the intermittent disruptions that you’re expecting going forward. In the event that this does carry on in 2016, the issues aren’t fixed yet, how is this going to affect your development plans there?

Yes, let me touch on the takeaway, the TCPL interruptions and while Mike grabs the rough number. I will see if we have it there on the Graben. But right now we’re hopeful that the recent release of the curtailments holds for the full year. There’s always a chance that could come in. And I know TransCanada has been talking a lot about this program as they’ve been implementing it. But at this point, we’re not anticipating big disruptions in 2016. We’re hopeful that largely we’re through the worst of that. I think it impacted us in the second quarter, about 33 million cubic feet a day was the impact in 2Q. What we’re signaling is there’s some chance in the second half of the year, but we hope it’s minimal and we hope 2016 it’s minimal.

Hi. You bet, Nick. With respect to gross inventory we have in the Eagle Ford; of the 600 wells, 300 are in the Graben.

Perfect. Thank you.

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

Thank you. Good morning.

Hi, Brian.

You’ve spoken on the cost decreases on the capital side. I wanted to see if you can spend some time on operating costs on a pre-unit basis, production plus transport looked like it was up substantially even quarter-on-quarter both in the U.S. and Canada and I wanted to see if this was just the result of production mix and asset sales, if there were one-offs in your outlook going forward?

Yes, I think the big driver – I think looking forward and where we’ve kind of indicated our guidance, we still feel confident. There’s a bit of lumpiness in the shape of our operating costs just now largely because of some stuff in the Permian, and actually getting our arms around some of the basic processes and systems we had in place. We actually think those are going to drop in the third or fourth quarter and will still end up where we expect it for the full year. I don’t know, Mike, if you have anything else you’d want to add there on operating costs?

For sure. In the Permian, we had non-reoccurring costs that hit us as well as really trying to address the processes and the systems that we had to kind of get up to Encana standard here. But very confident we’ll be on a commercial competitive level with respect to our cost going forward.

Great. Thanks. And then you’ve also spoken on some of the techniques on improving the EURs in the Permian but I think you made a comment that your base decline rate in the Eagle Ford shale has fallen by about 50%, and I wanted to see if you can comment on whether that improves your EURs on a going forward basis, if that’s just for the legacy production and what the drivers are?

Yes, Brian, it’s a good inside here because we really don’t think that this dramatically shifts EURs. What we think it does is just basically making sure you’re optimizing your production. We thought there were a lot of opportunities in the Eagle Ford to improve how we were managing things downhaul, so with artificial lift and basic production operations. And what we’ve done is delivered that. It really hasn’t shifted what the EUR is. It’s making sure we’re staying on it and not deferring production later in the life. This is kind of basic blocking and tackling but it’s been a nice upside since we bought it. But at this point, I wouldn’t add it on to the EUR.

Great. Thank you.

Your next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt. Your line is now open.

Good morning. Thanks for taking my questions. I appreciate the detail on current production, but just given the immediate growth in the quarter-over-quarter, could you speak more to quantify the impact of weather in the affected areas?

I’m sorry, Jeoff, could you say a bit more?

Just looking to understand the quantitative impact of weather that you mentioned as far as production in the quarter.

Okay, weather. Yes, I would say it was relatively modest. It actually hit us in three places. It hit us in the Permian, in West Texas. Largely though we did do some pretty good planning around this but it largely just delayed a little bit of the completions and drilling activity just moving things around. In the Eagle Ford, it actually had a little bit of impact on our construction of our Patent Trust South. We had some flooding, which called a little bit of delay. And then surprisingly enough, it impacted gas production into Haynesville because the big rains in North Texas and Oklahoma, the rivers actually flow through Louisiana and we had actually flooding in our Haynesville, which requires to shut some production in. But I don’t want to overemphasize this. This is a minor impact in the quarter. I know a number of other people were hit by it. But most of the impact was a slight delay to bringing on new production.

Great. That’s helpful. And then on the CapEx, can you provide a range for Q3 just given the focus proactively through year end that you mentioned in the reduction of non-core spending going forward? Just trying to better understand the trajectory on a quarterly basis going forward into end of this year?

Yes, I think Sherri indicated we’re still on track to be within our guidance. I think 3Q will be slightly larger than 4Q but not by a lot. I mean what we – as we mentioned earlier, we’re largely – most of our activity now is just in three of our assets for the remainder of the year; the Permian, the Eagle Ford and the Duvernay with the Permian being the biggest piece of that. So I think you can look at the remaining balance to our guidance and say we’ll spend slightly more of that in the third quarter and a little less of that in the fourth quarter.

Okay. Thanks. And last question from me specifically on the Permian, just looking at the blended type curve coming in at the high end of your previous range, could you provide some additional color outside of the highlighted wells just on leading edge completions and how productivity looks in those wells that you’re drilling now versus the type curve at this point?

Yes, we’re still kind of in a learning mode. What we’ve done is to really cast [ph] the boundaries with respect to completion size going from what was sort of a 1,300 pound per foot, we’ve tested all the way up to 4,000 pounds per foot. So what we’re finding is that, as I think Doug mentioned earlier, our clean-up timeframes are going anyway – shortest would be 15 days. They were actually going all the way up to 60 days before we hit those peak rates. But we are getting to our type curves. It’s taking a little bit of time to ramp up to that point. One of the benefits and this is a benefit if we actually saw in the Eagle Ford when we went to larger fracs has actually shallowed our declines and giving us stronger EURs. So that’s one of the reasons we’re doing that. So it’s still work in progress. We want to find that optimum design to get the optimum return.

Jeoff, how this is actually showing up and we’ve seen it in a couple of our plays is when you combine that with managing the pressure, what it means is we actually don’t have much decline in the first few months of production. So instead of sort of really large IP30s, what you see is, is flat or no decline for the first several months before you go into declining that. That’s what gives you potentially higher EURs and higher IP180. So it’s not that the IPs – maybe it will jump up to 200,000 barrels a day, it’s actually that wells will come on in 1,000 and stay there for quite some time.

Great. Thanks for the detail.

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

A quick question, what’s the level of confidence you have in that guidance number, the 270,000 barrel oil equivalent for the Q4 assets? Is that a coin test flip, is it 90% certain, is it in the bag?

Bob, it’s a lot is what it is. We obviously give this stuff – we’re paying a lot of attention to it. We’ve been saying this for a while that it would hit the 270. And our best estimates are we’ll do that. We have line of sight to what it takes to get there in terms of activity levels and programs. There’s always the chance if something doesn’t turn out like you expect, but our best view at the moment is we’ll hit that number by – and that’s a four-tier average number is what that is. It obviously represents big growth year-over-year, which is what we’re targeting.

Yes. And a follow up on the self-sourced proppant, can you talk a little about that? Is it mines you’ve acquired? Do you ship it yourself?

Yes, what we do there, Bob, is we don’t own mines, we don’t own rigs and frac fleets. We don’t think that’s the best way to maximize value. But we do think in our completion activities having the relationship with the sand mines ourselves and then managing the logistics of getting it all the way to our job sites maximizes the value. And that’s what we do. We’ve had this in place for a while and as we’ve made the changes to our portfolio, we moved those relationships around. So, for instance, some of the sand that late last year we were delivering into the DJ is now being delivered into the Permian and into the Eagle Ford. So we don’t own sand mines but we do contract directly with sand mines.

Got you. Thank you.

Your next question comes from David Meats of Morningstar. Your line is now open.

Thanks. Good morning. I believe I heard in your prepared remarks that if you were to get any increments capital, for instance, from an asset sale then the first priority would be to take care of the balance sheet and then some acceleration in the four core plays. So I guess my question is what would it take to allocate capital to the San Juan, the TMS and the DJ at this point?

Yes, it’s one of the things we’re looking at very carefully as we start – Sherri mentioned, as we start to look towards 2016 and beyond. I think with respect to the San Juan, as Mike mentioned, really strong recent well results. We’re actually doing what we call a deep dive on the asset and say, what’s our current view and has it shifted with this recent improvement in well performance and where would it sit and compete for capital. With the others at the moment, what we think is we need to take a pause because the four – what we call our four most strategic assets are the ones that we think really drive the value. The DJ is a very solid asset with good returns in today’s environment. We’ve got a great track record there. In fact, I think one of the consulting houses not too long ago actually issued a report saying we had the most economic wells in the play. But when we’re looking at the future, we say what’s most important strategically to the company particularly in this part of the price cycle? And we think those four strategic assets are the place to put capital and we’re evaluating them, where do our other assets fit, both compete for capital and fit in the long term.

Okay. And you mentioned in your news release the credit facility that’s being updated and increased until 2020. Is that guaranteed until 2020 or is it subject to redetermination in the interim?

No, that’s guaranteed until 2020. We can basically look at rolling over [indiscernible] each year and like I say, it’s a nice thing to have in place given the uncertainty and making sure that we have adequate liquidity.

Okay, perfect. Thanks very much.

Your next question comes from John Herrlin of Generale. Your line is now open.

Yes, sure, close enough. For the Permian gathering contract that you signed, is that with Medallion.

Why don’t I let Renee Zemljak here with us runs our Midstream, Marketing and Fundamentals team, I’ll let her describe what we put in place.

We run a very competitive RFP process, which is something that Encana typically does and so we have contracted with Medallion, and we’re very encouraged with the terms that we were able to achieve in that contract and we’re really looking forward to a long-term relationship with them.

Great. Regarding the Eagle Ford decline rates, Doug, what is the base decline rate now? You said you dropped it by 50%. What’s the base?

I’m going to look to Mike to see if he can help me with that. If we can’t grab it here quickly, we can follow up with you after the call. Mike, do you --

We’ve done a tremendous job here – I don’t have the decline rate at my fingertips but we’ve done a tremendous job focusing on the base looking at our official lift systems and we’re shallowing that base decline. I just don’t have the number.

Me and Mike can – what we’ll do is follow up with you on that, but across the portfolio this year we’ve actually cut about two points off that I think is 31.

Yes, actually on a budget basis we have a 31% base decline across all of our assets and we’ve shallow that down to 28%, so from 31% to 28%.

Okay, great. Last one from me is on your gas gathering, so if you look at the U.S., you’re running about $2.30 for gathering and processing. How much of that is fixed? And is there any way you’ll renegotiate since it’s kind of high?

It’s actually place-by-place and it all depends on where the market is and where capacity constraints do or don’t exists. Clearly in some parts of our system, the world’s moved on and things like the Marcellus showed up and moved the market to a different place where some of those contracts today unfortunately you would call them out at the market, so you can’t renegotiate them, and in other places you might be able to do so. But largely I would assume where we can make a difference, we have. The big thing we can do and Renee and her team does is in a number of those places we have excess capacity and we trade around that capacity to claw back a bit of those fees. And we do that as an ongoing basis.

Okay. Thank you.

Your next question comes from Jeffrey Campbell of Tuohy Brothers. Your line is now open.

Thanks for letting me back in for one more. I just want to ask a quick question and that is, are you planning to use the Duvernay dual-frac spread approach elsewhere in the portfolio?

I think one of the things we have to – you have to look at where you can. I think you guys know we use what we call our resource play hub or RPH model. And one of the elements of that model is how you integrate your systems like your water system, your production systems and these things, and what allows us to do that in the Duvernay is the combination of things. One is we have piped water to pads. You can actually haul that water in a day. And the second thing is you have to be able to store large amounts of sand on location, which is something we do in a lot of places. But clearly what we’re looking at and we actually had designed into our organization [indiscernible]. So the real question is, is can we – do we have the system in place in other places to be able to deliver the water and the sand. I think Mike we were pumping over 100,000 barrels of water a day and I think close to 1 million pounds of sand a day in that. So you actually have to have the systems in place to do that. You can’t run that many trucks.

Okay. Thank you.

Your last question comes from Barbara Betanski of Addenda Capital. Your line is now open.

Thanks very much. I apologize if this has been covered but it’s a question around the TCPL outages. If you could just speak to the volumes that were offline in Q2 due to those outages and also whether your price was affected? And what sort of volumes you’re budgeting for Q3 and Q4 that might be impacted? And I guess importantly how predictable is that maintenance on TCPL and what level of confidence do you have for the second half that you might now get affected again?

Yes, Barb, we did briefly cover this but happy to repeat it. In Q2 between the TCPL issues and an issue with a spectra [ph] operated gas plant, we had about 33 million a day offline. Right now we’re not being curtailed at all in the TransCanada system. We don’t anticipate large volumes the remainder of the year. All we’ve done is flagged it’s a risk, but we don’t anticipate that will be significant going forward. As far as price, the only real impact on price is if you decided to try to move your gas into different markets and therefore received a different price for the gas. But it wasn’t a significant issue, it’s more a volume item.

Okay. Thanks very much.

Yes. So before we wrap up, I just want to mention a couple of things. We made a delivered shift this quarter to disclose a lot more detail on technical information. We’ve had that request from many of you. I think you’ll see in our presentation today we gave a lot more operating results. And in addition when you look at our corporate deck at our Web site, which I think is just about to be loaded, it has a significant increase in the amount of technical information on each of our four most strategic plays. I’d encourage you to take a look at that. I just want to close by saying thanks to everyone for being very generous with your time this morning and look forward to talking about some very strong results in the third quarter.

Thank you very much folks. Our conference call is now complete.