Ovintiv Inc. (OVV) Q2 2013 Earnings Report, Transcript and Summary

Ryder McRitchie - Vice President of Investor Relations & Corporate Communications Douglas James Suttles - Chief Executive Officer, President and Director Sherri A. Brillon - Chief Financial Officer and Executive Vice-President Michael G. McAllister - Executive Vice-President and President of Canadian Division Jeff E. Wojahn - Executive Vice President and President of USA Division Renee E. Zemljak - Executive Vice President of Midstream, Marketing & Fundamentals Robert A. Grant - Executive Vice President of Corporate Development, Corporate Responsibility, Environment, Health & Safety and Reserves

Greg M. Pardy - RBC Capital Markets, LLC, Research Division Randy Ollenberger - BMO Capital Markets Canada John P. Herrlin - Societe Generale Cross Asset Research Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Robert Bellinski - Morningstar Inc., Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Brian Singer - Goldman Sachs Group Inc., Research Division David Snow Mark Polak - Scotiabank Global Banking and Markets, Research Division Menno Hulshof - TD Securities Equity Research

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Second Quarter 2013 Results Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] For members of the media attending in a listen-only mode today, you may quote statements made by any of the Encana representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Encana Corporation. I would now like to turn the conference over to Mr. Ryder McRitchie, Vice President of Investor Relations and Communications. Please go ahead Mr. McRitchie.

Thank you, operator, and welcome, everyone, to our discussion of Encana second quarter results for 2013. First, let me just start off with an apology for the delay in getting things started. We experienced some technical difficulties here on our end in setting up the line. So again, apologize for the late start. Before we get going, I must refer you to the advisory regarding forward-looking statements contained in the news release, as well as the advisory on Page 39 of Encana's Annual Information Form dated February 21, 2013, the latter of which is available on SEDAR. In particular, I would like to draw your attention to the material assumptions and factors in those advisories. Encana reports its financial results in U.S. dollars and U.S. protocol. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S. dollars and after royalties, unless otherwise noted. Assuming you've all read our news release, we will keep our prepared remarks brief and to the point in order to allow more time for questions. The focus of our prepared remarks this morning will be on our second quarter results and progress compared to our 2013 guidance. We will begin with Doug Suttles, Encana's President and CEO, who will discuss the company's second quarter highlights and our strategy development process. Sherri Brillon, our Executive Vice President and Chief Financial Officer, will then discuss our second quarter results. The entire Encana Senior Management team is on the line this morning, so please feel free to direct asset specific questions to the leaders of our operating divisions during the Q&A session. I will now turn the call over to Doug Suttles, Encana's President and CEO.

Thank you, Ryder, and thank you, everyone, for joining us on the call today. During the second quarter, we delivered a solid set of results and remain on track to deliver in line with our 2013 guidance. Highlights for the quarter include a nearly 70% increase in liquids production when compared to the second quarter of 2012 and a renewed focus on capital allocation and capital discipline, where we now expect our 2013 capital spending to be at the lower end of our guidance range of $3 billion to $3.2 billion. We are also putting new emphasis on our portfolio of emerging liquids plays. We are taking a rigorous and measured approach to funding these plays, evaluating each of our positions against their commercial potential, scale, and ultimately, their strategic fit. We are closely monitoring key performance parameters such as well cost, flow rate and ultimate recoveries against very specific targets. Of note, we continue to be encouraged by our Duvernay results and the early results in the TMS. And we have decided to exit our Mississippi Lime position in Osage County, Oklahoma. We are moving forward with commercial development in the San Juan, DJ Basin and Clearwater oil areas. Tracking the projects of the emerging plays as they're appraised will be a particular focus in the second half of 2013. The net results of our efforts over the first half of the year mean that we are now tracking towards the mid to high end of our cash flow guidance range of $2.3 billion to $2.5 billion. As we look ahead to the coming months, my top priority is to build our new strategy. To this end, I recently launched our internal strategy team that is tasked with assisting me, the Board of Directors and the Senior Management team in formulating a strategy that will create a compelling vision for Encana's future and sustainably grow shareholder value. I fully expect this work to be completed by year end 2013, and that 2014 will be our first year of implementing our new strategy. I do appreciate your patience given the importance of this work. As I stated 6 weeks ago, I believe it is critical we do this once and we get it right. I will now turn over the call to Sherri, who will go through our results in more detail.

Thanks, Doug, and good morning, everyone. In the second quarter, Encana generated cash flow of $665 million or $0.90 per share and operating earnings of $247 million or $0.34 per share. Year-to-date, our cash flow totals about $1.2 billion or $1.69 per share, with operating earnings totaling $426 million or $0.58 per share. Average natural gas production for the quarter was about 2.8 billion cubic feet per day and liquids production averaged about 48,000 barrels per day. For the year, we expect natural gas production to average between 2.8 and 3 billion cubic feet per day, and we expect liquids production to average between 50,000 and 60,000 barrels per day. We expect our 2013 exit rate for liquids production to be in the range of about 70,000 to 75,000 barrels per day. Encana maintained its strong liquidity position through the quarter with a period end balance of about $2.9 billion in cash and cash equivalents. The proceeds received during the second quarter from the sale of our Jean Marie assets, as well as the proceeds received during the first quarter from the sale of our interest in the Kitimat LNG facility, along with other minor transactions, bring our year-to-date net divestiture total to roughly $650 million, in line with our 2013 guidance range of about $500 million to $1 billion. We expect to end the year with cash and cash equivalents of roughly $2 billion, enabling us to maintain our financial flexibility as we head into 2014. In June, we extended the maturities of Encana subsidiaries revolving bank credit facilities to June of 2018 and reduced the amount available under Encana's Canadian facility. In an effort to decrease costs in light of our reduced capital expenditure programs over the last 2 years, we decided that it was appropriate to reduce the amount available under the Canadian facility from CAD 4 billion to CAD 3.5 billion. The amount available under the U.S. revolving credit facility remains unchanged at $1 billion. As of the end of the quarter, there were no outstanding balances under our company's revolving credit facilities. The news release highlights the additions we made to our hedging position during the quarter. We now have about 2.3 billion cubic feet per day of expected 2013 natural gas production hedged at an average price of $4.37 per Mcf. With approximately 75% of our expected July to December 2013 natural gas volumes hedged at this attractive price, the estimated sensitivity of our 2013 projected cash flow to a $0.50 per Mcf change in the price of NYMEX natural gas is about $30 million for the balance of the year, assuming normalized historical levels for basis differentials. Encana actively hedges its basis exposure using a combination of physical transportation and financial basis hedges. We currently have about 50% of our 2013 AECO basis hedged, a position that partially protects us from the recent widening of the AECO basis differential. I'd like to address our cost performance for the quarter, as well as the primary reasons why our operating, as well as our transportation and processing costs were higher than last year. Total operating expenses increased by $31 million in the quarter compared to the second quarter of 2012. The increase was largely a result of higher liquid production volumes and an increase in expenses related to agreements with third parties that are recoverable to Encana through higher revenues. Transportation and processing expenses increased by $47 million during the quarter compared to the second quarter of 2012. The higher costs are driven primarily by higher fees associated with recovered NGL volumes, resulting in higher revenues and increased fees associated with midstream facilities, which Encana divested in 2012. That said, our 2013 operating transportation and processing and administrative costs continue to be in line with our guidance and expectations. And the teams remain focused on extracting cost savings and efficiencies and improving margins. Across the company, we continue to actively look for ways to reduce cost, improve efficiencies of margin, strengthen cash flow and ensure the sustainability of our business. Each operating division has prepared specific initiatives and efficiencies to drive further cost improvements into the second half of the year. We are targeting to achieve some of these cost structure improvements within the next 12 months, and we expect our efforts to begin impacting the company's financial results in the second half of the year. I will now turn the call back to Doug for some closing remarks.

Thanks, Sherri. Overall, the second quarter unfolded as expected, and we remain on track to reach our guidance for 2013. Across the organization, we continue to focus on disciplined capital allocation, driving down cost and objectively evaluating the performance of our emerging plays. I would like to take a moment to acknowledge David O'Brien for his tremendous contributions to Encana as the Chairman of the Board of Directors since the formation of the company in 2002. In today's news release, it was announced that David will be stepping down from the Chairman seat, but he will remain a Director of Encana. Clayton Woitas will assume the role of Board Chairman. I'd like to thank David for his many years of leadership, and I look forward to the continued benefit of his knowledge and expertise through his role as a Director. My experiences with the Encana team over the past several weeks have confirmed what I believed when I first accepted this job; that Encana is the right fit for me. This is a company with a proud history of success that is ready to get back to winning. And I believe my skills and experience can help make that happen. I believe Encana will be a leading North American energy company for a long time to come. Over the coming months, as we work through our strategy development process, I will continue to communicate with the investment community on the progress that we are making towards establishing a new strategy and plan for Encana. I'm very excited about this opportunity, and I'm also very confident that we will create a successful future for our company. Thank you for joining us today, and our team is now standing by and ready to take your questions.

[Operator Instructions] Greg Pardy with RBC Capital.

Just a couple of questions for you. First, what is your current oil and gas -- oil and liquids production rather? And then secondly, I know you scaled back capital a bit, but could you talk about any reallocation of capital?

Okay, Greg. In just a second, I'll hand that over to Sherri to provide the detail. But just as a point of process, we recently took a hard look at our capital spending through the year. We had been generating savings in a number of areas. Some of those coming through the programs being more efficient than we had forecast, and in other cases, in adjustments to the timing of the programs. The organization brought forward, I think, something more than $300 million of potential capital options. We decided to exercise those options to the tune of about $90 million and return the rest to the balance sheet, which is one of the reasons why I believe we'll end up at the lower end of the range. But Sherri, if you could cover maybe more detail on Greg's question.

Great. Thanks, Doug. Specifically, around oil and liquids production, our Q2 2013 ethane production -- I have to go back to my chart here, bear with me.

Sure.

Okay, here we are. All right. Are you looking for the 2013 forecast volumes, or what we're actually at right now?

No, just a ballpark on current rates right now.

Okay. I think -- sorry about that, I had my outlook.

We can come back to it, Sherri.

Okay. The question around the capital side, when we looked at our outlook right now, we expect to be at the bottom end of our capital guidance at $3 billion to $3.2 billion for the year. We have gone through a midyear review. And the teams have identified with a high level of confidence, capital efficiencies or savings are around $200 million. We expect that those will increase as we go through the balance of the year and as the teams have more confidence in realizing those additional efficiencies beyond the $200 million. So at midyear, we had $200 million of savings identified. We looked at a portfolio of close to $300 million in different projects and opportunities. And we decided that we would fund from the savings. We would reallocate $100 million to additional projects, primarily in the U.S. and $100 million to our balance sheet. We expect, as we go through the year, that we'll realize additional capital savings as the team acknowledges and recognizes those. The other piece of the equation here is that cost side, we've got quite a bit of cost initiatives underway, cost savings identified. The teams are looking at seeing some of those savings roll through to the end of the year, so we should see them in the next 6 months as part of our financial statements. And some of the initiatives that we've looked at, we've experienced year-to-date about a 7% attrition, and that's by voluntary departures as well as performance management. And we've been looking at backfilling critical positions off of that attrition. We've been looking at efficiencies and opportunities to manage down our cost in all of our areas as well as in the corporate G&A side with respect to travel courses and travel conferences, that kind of thing. So we're feeling quite confident that we're going to be able to achieve our $100 million to $150 million in G&A and operating cost savings, some of which will be recognized in this year and some over the next 12 months. And I've just got my [indiscernible] report. The July 15 to 21, so just the past week, we were producing 52,000 barrels per day of total liquids.

Okay. And maybe just the last one. Doug, you touched on the TMS and the Duvernay. I know it's still earlier stages with both those plays. But is there any color you, or Jeff rather, could just add on, on progress on those plays right now?

Yes. Greg, let me ask Mike and Jeff. Maybe Mike cover the Duvernay, then Jeff will cover the TMS.

It's Mike McAllister here. On the Duvernay, we continue to be very, very pleased with our 805 [ph] well up in Kaybob, where it's currently producing 900 barrels a day of condensate, free condensate and about 3 million bay of gas. So and that's choked back rate. We're actually constrained going into this assignment -- [indiscernible] plant. So really, really encouraged with the results. We think we've cracked the technical nut with respect to the completions, and I'm able to turn it over to Jeff on the TMS.

Greg, it's Jeff. The TMS has performed very well in the last quarter. We've had a number of significant events that have occurred in the quarter. I think one of the key drivers for us is to look at our drilling performance and our overall cost performance. In the last 3 wells, we have, by and large, met -- hit our targets, our target cost projections for the play, normalized for completion intensity. So that's very good news, and that was something that we struggled with in the past. One other item I should add on the TMS as well is that we have 2 wells, Anderson 17-1, Anderson 17-2 that are currently being completed and being brought on stream. And we'll have results coming up soon. And obviously, there's industry activity going on right now, and we've been monitoring that closely as well. One event that occurred to TMS this year that was very significant for us, that I may remind everyone on is House Bill 1698 that was passed by the Mississippi State House and Senate. And that was a reduction from 6% to 1.3% on the severance tax. And that equates to about a $700,000 savings per well. So the short on the TMS is things are progressing well. We're feeling much more confident on our ability to execute on our cost structures. We have a line of sight to our long-term projection of $12.8 million, and we feel the upcoming 2 Anderson wells are really going to be indicative of the future of the play.

Last one for me just on the Duvernay, Mike, how close are you to moving to multi-well developments pad drilling in the Duvernay?

Yes, Greg. We're looking at next year going into multi-well pads in Duvernay. So we're basically still doing single wells, but next year it will be multi-well pads.

Your next question comes from the line of Randy Ollenberger with BMO Capital Markets.

Just 2 quick questions here. One a bit of follow-up on the production side of things, so I think Sherri you said you're at 52,000 barrels a day. You were at 45 over the first half of the year here, so it looks like you're going to have to average at least 55,000 over the balance of the year to hit guidance. Just wondered if you can give us a little bit of color on where you expect to see higher volumes over the second half of the year to bring you in line with guidance? And then my other question is for Doug. Just in terms of strategy review, I know it's ongoing, but I guess my question is are we really going to have to wait until the end of this year, beginning of next year before we get a sense of where you want to go? And I guess related to that, I mean if you start to see your recent conclusions ahead of time, will you be making some moves on the capital allocation front for 2013, or will you just wait until 2014?

Thanks, Randy. Just I'll make one comment on volumes and then maybe ask Mike and Jeff, after I answer your strategy question to fill in some color. It's worth noting in 2Q that an outage at the Musreau plant actually had a net effect of 3 MBT, 3,000 barrels a day in the quarter. And that plant's back online, so it's worth noting when you're thinking about the math. But I'll ask Mike and Jeff to talk about where they see the volumes coming through in the second. On strategy, I think the critical point here is we've got the team underway. We are accessing some external help as well independent from our internal team to make sure we look at this carefully. We are doing, what I'd call, a roots up look at our asset base and the strength of it, the opportunity in it, the margin structure in it. That forms a key component. We're looking real hard at our core skills and what we're really good at. And we're also taking a hard look at our competitive position, how good are we, not only as an enterprise, but also in a play-by-play sense against our competitors. You can imagine to do that right takes some time. In addition, we obviously have to take a view of the future where the opportunities will be. And then through all of that, we'll shape the strategy. We will have it done by the end of the year. If we got it done sooner, we'll obviously come back to you and tell you. In the meantime, though, I'd started last month. We're taking a very hard look at where we spend our money and making sure it's delivering the results. And then it feels like it will be a fit, but we don't want to make big macro decisions until we're certain where the strategy will be. But if I could maybe hand over to Mike and Jeff on volumes.

Randy. As Doug had mentioned, we had an outage on February 26, it's actually the Pembina Musreau Deep Cut plant, and it was out for 8 weeks. It was out because of a failure on electric motor, 10,000-horsepower electric motor. The effect of that in the first half of the year was about a 3,000 barrel a day hit on our production. That plant came back up on the 20th of April and has been running fine ever since. So it sort of addresses the NGL question. On volume growth going into the remainder of the year, we have 2 pads on production in Gordondale, six-well pads on production Gordondale with another 2 pads planned here. We'd come onstream between now and the end of the year. And so that's where will see the majority of our oil growth coming out of the Canadian division going to our year end exit rate. With that, I might turn it over to Jeff now to talk about the U.S. division.

Sure. Current production is about around 14,000 barrels a day on oil, 9.1 thousand on NGLs. And our growth is really widespread. Our biggest driver area is the DJ Basin, where we have 3 rigs running right now and anticipate growing our rig count to 5 by year end. But we really see broad growth across our portfolio with our recent renegotiation of a liquid extractions contract in the Rockies. You're going to see growth in our NGLs and condensate in the Piceance Basin and Jonah. And to a lesser extent, you'll see growth coming from some of our emerging plays, like the San Juan, Eaglebine and TMS. But it's really broad based and primarily coming from, what we call, our base commercial assets.

Your next question comes from the line of John Herrlin with Societe Generale.

With respect to liquids volume growth versus capital redistribution as in the dividends, is the dividends sacrosanct, or is it something you'll address once you know more about your own conventional program? That's question 1. Question 2, you obviously have a great unconventional skill set. Would you ever return to more conventional-type exploration?

Okay. It's Sherri Brillon, John. Thanks for your question. Around the dividend, we look at the dividend quarterly, and at this point, we have no plans to change it. We do expect, as we go through our strategy review, this will be one of the variables that are examined.

And John, on conventional versus unconventional, having been here, I think, a bit more than 6 weeks now and had a chance to meet, I think, probably over 80% of the organization and look at every one of our assets in some degree or another, it's clear we have a great set of skills when it comes to the resource play hub modeling where we have scale and large programs and we can drive efficiency through them. And it sort of resources the point I believe in pretty deeply, which is you have to know what you're good at and you need to make sure before you lay capital in, you are good at it. So we will examine that as we go forward, but I would expect that the combination of our asset base and our core strengths will play a big role in our future.

Okay, great. Last one for me. On a going forward basis, do you think maybe you can break out oil from NGLs rather than combined?

Well, John, we can. And I will tell you that because I think it's an important point, even today and when we look forward, we're now looking, not only at the breakout between oil and NGLs, but looking at the breakout of the components within the NGL stream. I think this will be an important element of thinking about where you invest in the future.

Your next question comes from the line of Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I had a couple of quick questions on the building of the new strategy. One would be, will you do anything opportunistic in terms of bolt-on acquisitions between now and the time that the strategy is finalized? And then I have a follow-up.

Bob, in terms of big strategic acquisitions, we won't be doing any before the strategy comes out. Of course, we're always looking at tactical acquisitions where we might be adding onto a position, or in some cases, just looking at the fit of certain assets like what we discussed about the Mississippi Line in Osage County, Oklahoma. But big macro acquisitions would be something that would be a part of the strategy. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Great. And then the follow-up would be, how broad in net are you casting in terms of strategy formulation? Is something like a corporate merger, corporate acquisition all the way to a sale? Is it that wide a focus, or is it really playing with the cards you've already been dealt?

Bob, one of the things in my discussions with the board has been that we haven't actually eliminated any course of action as part of the strategy, other than we're not going to get out of the oil and gas business. I can confirm that. But we are going to look at a very wide range of alternatives and look at what we think is the best one, the best choice to make sure that we can sustainably grow value. And so right now, at this point, we haven't eliminated any potential options.

Your next question comes from the line of Robert Bellinski with Morningstar.

Looks like the Haynesville volumes fell a bit despite the sequential increase in spending and the number of wells drilled. I was just wondering, was completion in tie-in activity delayed for some of those wells, or are you drilling shorter laterals, or is there some other factor that came into play this quarter?

Robert, it's Jeff Wojahn. I think I can get you up to speed on our Haynesville program. As you know, we restarted our program. And as of Q2 2013, we have a current rig count of 4 operated and 1 not operated. We've drilled 8 wells so far, completed 3, and our costs are on track in that $14 million range. So our cost performance is expected. This year, we've only brought on 3 wells to date, and one of the wells has been on for a little while now. It is on slowback protocol, but it is meeting our expectations, it's flowing around 15 million a day and at around 8,000 pounds flowing pressure. And the other 2 wells, the so called Blackstone wells, are just coming onstream right now. So my anticipation is as the program continues to ramp up, you're going to start to see the impact of those new wells being brought on. And you'll see the Haynesville numbers kind of arrest the decline that you see in the Q2 numbers and start flattening out.

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just in regards to the AECO price. You guys mentioned some weakness that's coming to the market here seasonally, and I was just curious with the -- if you could give us any additional color on how the basis hedges will affect your realizations in the back half of this year? And then I guess a second follow-up question, at what price do you start to look at your gas drilling activity in Canada? And where does that start to look a little bit less attractive versus the U.S.?

Matt, this is Renee Zemljak. With regards to the AECO price and the AECO basis differentials that we're seeing, Encana's been pretty deliberate about protecting our risk associated with a widening basis differential for AECO for quite some time now. We do have about 50% of our expected production for 2013 and actually '14 and '15 as well, protected against a widening basis differential with some transportation contracts that gets our production to neighboring markets, as well as basis hedge contracts that have been done. The weakening that we've seen most recently is a result of TransCanada's new toll structure that went into effect July 1, because their new toll structure has allowed the ability for interruptible capacity to be at very high tolls, the basis differential between actual AECO and Ontario has widened out. And because of the toll structure, we're actually seeing less volumes flow from Canada over to the Eastern markets. We expect that, that situation could correct itself come this winter when the contracts at TransCanada has actually increases. But due to the uncertainty that we've seen over the last year or so, we've been pretty deliberate about protecting ourselves and like we said, we have about 50% of our expected production protected for the next 3 years.

And Matt, this is Doug again. I think on at what point you reconsider your programs, it's obviously something you watch closely. But it's also important to note that we have joint venture partners in a number of these big programs, and that's actually a conversation, before we made changes to the plans, we would have to have with them. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just as a second quick follow-up question on the divestitures side, could you give us, I guess, the associated production both with the divestiture assets and then also was there any production associated with the San Juan acquisition?

Maybe, Jeff, do you want to cover San Juan?

The San Juan is primarily a land acquisition. It had minor amounts, but very minimal.

John, this is Bob Grant. Just on the Jean Marie divestiture, which we culminated in the second quarter, that was roughly about 108 million cubic feet a day of gas.

Great. And then just the last question for me, I was hoping to get an update on how you guys are thinking about the Eaglebine, the well results you've seen so far, maybe a little update on the EURs? And then I guess my second question would just be on the TMS. I know you talked about the initial well results being encouraging. I was hoping to get maybe a little bit more color on how those results are tracking versus your expected EURs in the play given some of the longer production data you have?

Matt, just real quick on the kind of frame here. I think, just to bring you back to capital for a minute, we -- as Sherri mentioned, we took a hard look at the savings that were being generated and where to redeploy them. And we did decide and Jeff will fill in some of the details, we did decide to allocate some additional money to the sand portion of the Eaglebine play. On the TMS, I think as Jeff described earlier, there were 2 important elements to that program this year. One is to demonstrate that we could drive our cost down fairly substantially, and the good news is in our most recent wells, we're proving that we can. The latest 2 wells, which have a new frac design, are literally just starting up right now, and so we'll share that as those results become available.

Thanks, Doug. On the Eaglebine, I can maybe quote some numbers to give you more details. There's really 2 plays that we're pursuing in the Eaglebine, one which we call lower Woodbine sands, Eaglebine sands. We have 2 wells at Weaver State, unit 1H and 2H wells. Both those wells IP'd at around that 350 barrels a day range, and those are 7,000-foot horizontal wells with costs trending in the $7.5 million range. We have a fair amount of industry activity around this which we monitor closely. And based on the Weaver State wells and the confidence the team and the progress the team has made on well costs, we've moved ahead with a 8 well Woodbind Sand, Eaglebine Sand program for later on this year. We anticipate we'll have about 4 wells drilled and completed and brought on stream by year end on that program. In regards to the Lower Laminated shale or some people call it the Eagle Ford Shale, we have 2 wells onstream right now. And we're really looking at the results of those wells and seeing if they meet our tight group [ph] performance. I really don't have too much of an update on that side.

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

Jeff, you talked about adding 2 rigs in the DJ Basin, and that, that was a key area for oil growth the rest of the year. Can you just discuss what you're seeing regionally on your assets and how you evaluate running them?

On the DJ Basin itself?

Yes. Your DJ position.

Yes. We're relatively modest position to the DJ Basin, although very attractive, because it sits in the heart in the play and the over pressured Wattenberg Field area. And this year, we've really focused on cost reductions and lengthening our horizontals. As I mentioned before, we're increasing our rig count from 3 to 5. But I think one of the key elements is that the team has made steady progress relative to, not only increasing its reliability, but bringing cost down. We started out 2012 with $7 million for a 4,500-foot horizontal. And today, we've added a number of wells in that $5 million range for even longer laterals up to 7,000 feet. So we really feel for Encana, this is one of our drivers for growth. It's a top performer relative to economic returns. And we're just moving forward with it. We're very happy with the progress we've made to date.

Great. And my follow-up, Doug, and I followed up to, I think, an earlier question that Bob Brackett had asked. What is the importance of increasing oil in the production mix strategically, and what is the level of confidence that there is sufficient organic opportunities within the portfolio to make that happen?

Brian, I think that -- this is one of the questions we're asking in the strategy, is I think that as over the last couple of years, the company has tried to increase the amount of liquids in its portfolio. But it's one of the questions we're going back to as we look at strategy and where does that fit. I think as you've heard, we have a couple of opportunities that are emerging in our portfolio, which do have real scale potential in them if we can demonstrate the right sort of economic performance. And that's, in particular, the Duvernay and the TMS because we have very large acreage positions there. Some of our other positions are more modest as you recently heard Jeff described in the DJ Basin. This will be one of the things we address in the strategy is what role liquids play and if we believe they play an important role in the future, what would be the plan to actually make that happen.

Your next question comes from the line of David Snow with Energy Equities, Inc.

I'm wondering about the, I think, you said $12.9 million long-term TMS well cost. Evidently, you've gone away from those TMS 90 and TMS 150 super fracs to a somewhat less-intensive frac. And I guess that you're starting to look at successfully doing wells above the rubble zone. And I'm wondering if that combination doesn't lower the cost of your target just a little bit.

There's a lot of parts to your question. This is Jeff Wojahn, I'll try to answer some of those questions. We have made a significant amount of technical improvement or understanding of the reservoir. One of the trials that we did this year was to try out slick water frac-ing technology versus a hybridized gel program. And we've come to -- and this is a good thing. We've come to the conclusion that the way to go forward on the play is through hybrid gel jobs. So we have used the terminology, TMS 150 or 90, and that represented the amount of pounds of sand that we were using in our trials. Generally, we are continuing with the same level of sand intensity regardless of whether it's hybrid gel or slick water. Really, the slick water and hybrid gel component are related to the transfer mechanism rather than the amount of sand that we put in the wellbore. And we continue with those trials today. In regards to the placement of the well, what we have observed is it's a very important not to drill into the rubble zone because that's where we have lost circulation issues. By and large, as we increase the intensity of our fracture stimulation program, we feel that we create more stimulated rock volume, and ultimately, treat the entire pay zone more effectively. In regards to the above the rubble zone or below the rubble zone, I think we're gathering information on both. But what I've seen relative to the micro seismic information and what the teams believe relative to their modeling, work is that we really are affecting -- effectively stimulating the entire interval. So we're making good progress technically on where we're going, and I think we're headed down the right path.

Are you leaning toward the 150 or the 90 pounds?

So far, what we've seen is bigger is better.

And that adds a little bit to the cost as well, I guess?

And may also increase EURs. So those are the relationships that we're trying to understand more [indiscernible] today, and there's a little bit of a, we call it, design of experiment, and a little bit of experimentation going on to optimize that before we move forward with our commercial plans.

When do you think you will reach that point of going forward with commercial plans?

Right now, our focus is around the 2 Anderson wells, the 17-2 and 17-3. There's also a number of industry wells that we're monitoring closely. And based on that set of information, I think we're going to relook at the play and establish our strategies from that group of wells.

So probably by the next conference call, you'd have those data points?

We'll certainly have some flow information on those data points. We look forward to telling you about that.

Your next question comes from the line of Mark Polak with Scotiabank.

Sherri mentioned that the dividend would be one of the variables examined during the strategic review. You guys have previously talked about some of the levers you have to sort of maintain that being G&A reductions, efficiency gains and the capital program and the drip program as well. Looked like you had a pretty positive response to the new drip program throughout the quarter. Just wondering kind of your thoughts on that going forward? And if you can quantify what kind of G&A reductions you're hoping for and as well on what kind of gains in terms of efficiency on the capital program?

It's Sherri Brillon. Actually, we did have quite a bit of uptake on our drip program. We saw a 26% participation rate. So for the 6 months ending June, we issued about 2.2 million shares from treasury, common shares from treasury. And this reduced our cash outlay around our dividend for the quarter by about $39 million. We expect that we'll continue with the drip as we work through the strategy review. And I think that while the dividend is certainly one component, there are a number of variables that we'll look at as we go through that strategy review. And your other question was around the...

Potential G&A savings and capital savings.

Well, our target is $100 million to $150 million in G&A and operating. And with that, we've got, I think, probably we should be able to recognize a portion of that in the next half of the year. But that's really a savings that we've identified that we probably will see being realized more into 2014 as we start to work off of these reduced cost structures, both on the administration side, as well as the operating side.

Mark, this is Doug. On capital, there's 2 levers inside of there, which we're looking at now, and we'll continue to look at through the year and as part of strategy. Of course, one is how efficiently we can develop reserves with our capital dollars and the organization has clearly got that in its sights. So how do I reduce well cost and increase well rates and recoveries? And in a number of areas, there's been good progress this year. But there's a second lever here that we have to examine, which is to which assets do we deploy capital to. The good news is we have a large set of assets. We have a lot of choice in the portfolio, but this is an important lever, which we're looking at very closely is are we distributing the capital to the assets which create the most leverage?

On the $100 million to $150 million target in savings, that's split fairly evenly between G&A and OpEx?

Actually, we kind of grouped the number together as we look at it, because there's a lot of interdependencies relative to the G&A and the operating expenses. So I don't really have a formal breakdown of the 2 components. It's been a target that's been set as a total of the 2.

Your next question comes from the line of Menno Hulshof with TD Securities.

I've just got a quick question on asset sales. Looks like you're sitting at about $650 million year-to-date. So my question is, what else do you have on the block right now? When is it possible that you break through that $1 billion target for the full year?

We have a few opportunities that we still have, that we're looking primarily more for joint venture partners, for instance, the 10% that we still have in our Cutbank joint venture. As you know, the market has become much more of a sellers' market and -- or buyers' market in the end. What happens is that we've always got these opportunities. We don't want to extend out too far relative to opportunities because we want to make sure that the strategy group looks at all of our assets and make sure that any joint ventures or further joint ventures or dispositions fit the ongoing plans as they see them through the balance of the year. So is there an opportunity to increase that? Potentially. But I would say that's probably a low chance at this stage of the game.

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

Before closing, I'm just going to turn it back to Doug here for some quick final comments.

Thanks, Ryder. And I do want to thank everyone for joining us, and I'd just add my apology to those [indiscernible] that with the difficulty in getting the call started. Just as we think about the second half of the year, I just wanted to list what are my 4 priorities and the 4 priorities of this management team. And the first and foremost is about pulling through these cost efficiencies. They're beginning to show up, and as Sherri described, they should begin to be realized in the second half, and of course, they should be sustained beyond 2013. The second is this very important point about capital discipline. We need to make sure the dollars we invest generate very good returns, and that we're making very clear choices about what we decide to fund. And that's both the tactical item in the short term and a strategic item in the long term. The third one is we have our sights very clearly on exiting the year at the range of 70,000 to 75,000 barrels a day of liquids. And we know where those are going to come from, and we'll be tracking that very closely through the year. And I'm confident we'll make that happen. And then finally, by the end of the year, we need to have our new strategy in place, and our 2014 plan needs to reflect that new strategy. And we will communicate with you on that as it's developed. So just, I'll hand back to Ryder, but once again, thank you for joining us on the call today.

Great. Thank you, everyone, for joining us. For those of you that may have missed a portion of our call, the replay and transcript will be available on our website later today. So thanks again, and that includes our -- concludes our call.

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