EXCO Resources (XCO) Q2 2014 Results - Earnings Call Transcript

| About: EXCO Resources, (XCO)

EXCO Resources (NYSE:XCO)

Q2 2014 Earnings Call

July 30, 2014 10:00 am ET

Executives

Christopher C. Peracchi - Director of Finance & Investor Relations and Treasurer

Harold L. Hickey - President and Chief Operating Officer

Mark F. Mulhern - Chief Financial Officer and Executive Vice President

Harold H. Jameson - Vice President and General Manager of East Texas/North Louisiana Joint Venture area

Michael R. Chambers - Vice President of Operations, General Manager of East Texas/North Louisiana Division and Vice President of East Texas/North Louisiana Division

Analysts

Will Green - Stephens Inc., Research Division

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Stewart Glickman - S&P Capital IQ Equity Research

Brian Singer - Goldman Sachs Group Inc., Research Division

Owen Douglas

Operator

Good morning. My name is Lianne, and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Schedule Second Quarter 2014 Earnings Release and Conference Call. [Operator Instructions]

Thank you. Chris Peracchi, you may begin your conference.

Christopher C. Peracchi

Thank you, Lianne. Good morning, everyone, and thank you for joining EXCO Resources Second Quarter 2014 Conference Call. Hal Hickey, our President and Chief Operating Officer; and Mark Mulhern, our Executive Vice President and Chief Financial Officer, will provide our perspective on EXCO's quarterly results. We will also provide some insights as to how we see our business evolving followed by Q&A session. You can access our second quarter review slides on our website excoresources.com, and we will refer to these by slide number during our remarks.

With us today, in addition to Hal and Mark, are other members of EXCO management. Since much of our remarks today will concern our expectations for the future, they are subject to numerous risk factors, as elaborated upon in our 10-K, 10-Q and other filings. These comments constitute forward-looking statements within the meaning of the Securities and Exchange Acts. Such forward-looking statements are subject to certain risks and uncertainties, as disclosed by EXCO from time to time in its filings with the Securities and Exchange Commission. As a result of these factors, our actual results may differ materially from those indicated or implied by such forward-looking statements.

Now I will turn the call over to Hal to begin.

Harold L. Hickey

Thanks, Chris, and good morning. We thank you for your interest in the EXCO Resources conference call to review results for the second quarter of '14.

Before I get into the details on EXCO's operating results, I want to follow up on the macro commodity thoughts we discussed on our last earnings call in April. On the oil side, we're obviously, pleased with the elevated price of oil. Our expectation is for continued strength in oil prices as global, geopolitical risk remains high. Our July '13 Eagle Ford acquisition has helped diversify our commodity mix, and oil sales made up about 30% of our second quarter revenues.

On the natural gas front, while it's been hot here in Texas, summer in most of the country's been colder than last year and coupling weather with supply, natural gas storage injections have been strong. Near-term natural gas prices have fallen from the $4.70 range in mid-June to the $3.70s now, and EXCO's stock price has been negatively impacted, despite the fact that for '14 we're swapped at about 67% of our 2014 production guidance at $4.23 per Mcf.

Notwithstanding the near-term volatility in natural gas prices, we remain positive on the multi-year outlook with longer-term expectations for growth in natural gas demand from power generation, manufacturing and petrochemicals, exports to our neighbors and LNG exports. These factors will create future opportunities for EXCO.

Now, let me address the primary question that early reports on our release regarding capital expenditures. We got approval to increase our capital budget by up to $80 million in June when natural gas prices were in the high $4s. We established our operational rig plans for the second half of '14. Now shifting natural gas prices to the high 3s is causing us to reevaluate our plans. Now as you'll see, we're guiding 2014 CapEx to be $400 million to $440 million, up from our original $368 million budget. We're trying to strike the right balance of capital deployment and future production growth.

I want to assure our stakeholders that as we make decisions on what capital we spend and where we invest, we'll consider both short and long-term impacts on our balance sheet and income statement. We continue to evaluate industry trends, commodity prices and internal operational and financial analyses to assess potential modifications to our drilling program. We remain focused on efficiently managing our capital expenditures as part of our development program. Any additional development will be incorporated into our hedging strategy and we may enter into additional derivative contracts to protect our return on investment. Additional develop in '14, resulting from our capital budget flexibility, will primarily impact 2015 production volumes due to the timing of when the potential additional wells are turned to sales. Now before I turn to our results and, frankly, to head off any questions that I know you're going to ask, the CE search remains ongoing and we will update you when appropriate.

Now turning to Slide 3. This slide provides the key takeaways from today's call regarding our first quarter results. EXCO delivered solid results ahead of guidance and we continue to focus on operational execution and enhancing our liquidity. We remain focused in 3 strong shale positions as you know and have an experienced operating team with a demonstrated ability to improve efficiencies, drive down cost. Our $500 million senior unsecured notes issuance in April reduced our secured borrowings and added length in term to our capital structure. Our stronger balance sheet and our stronger liquidity will help anchor EXCO's future growth.

Turning to the highlights on Slide 4. Yesterday, we announced results for the second quarter that exceeded our expectations. Adjusted EBITDA of $105 million exceeded the high end of guidance. Production for the quarter of 383 Mmcfe per day was above the high end of guidance and was driven by oil production of 579,000 barrels and 31 Bcf of gas production. Capital expenditures were in line with guidance. Thanks to our employees and contractors, we drilled 32 and turned-to-sales 25 wells in the quarter, as we continued to operate safely and in compliance with rules and regulations.

On Slide 5, you can see a depiction of EXCO's 70,000 net shale acres across East Texas and North Louisiana. During the quarter, we operated 3 rigs focused on manufacturing in our Holly area in DeSoto Parish, Louisiana and 2 rigs focused on appraisal, testing and delineation in the Shelby area of East Texas. We drilled 11 wells and turned-to-sales 12 wells in the quarter in East Texas/North Louisiana. Our core Holly position includes 30,000 net acres in DeSoto Parish where we had approximately 360 wells flowing to sales at quarter end. During the quarter, we drilled 7 wells and turned-to-sales 10 wells in Holly. We continue to manufacture this core asset on 6 wells per section and with additional data, we have increased our proved reserves from 6.3 Bcf per well at year-end 2013 to 6.9 Bcf today.

Three of the wells we drilled are on our first cross unit development in DeSoto Parish where we're drilling 5 wells in total with 5,000 to 8,000 foot laterals as compared to our typical 4,200, 4,300 foot Holly lateral. With cross unit development, we're able to drill across unit boundaries and contact more horizontal section with longer laterals from a single wellbore, resulting in additional recovery and improved economics. Cross unit development will enable us to drill at least 10 sections in which we have not booked undeveloped reserves due to a major faults presence.

We've been at the forefront of Haynesville manufacturing, so we now have the opportunity to optimize our base production, tap the upside of our HBP assets. To optimize our base production, we've initiated multiple projects including refracturing of wells to capture new reserves and accelerate production, reducing operating pressure with compression projects and installing artificial lift to minimize base production declines, and we are very, very encouraged by our initiatives.

We recently completed our first re-frac stimulation test in DeSoto Parish. This test consisted of a fracture stimulation treatment on 2010 vintage well to re-stimulate the shale reservoir near the wellbore. We pumped 1 continuous job for 15 hours, using a temporary diverting agent to stimulate multiple sections of the lateral. We've seen a 1.3 million cubic feet per day increase in production and a 2,800 psi increase in tubing pressure noting that the well is continuing to clean up. While we're still analyzing this first re-frac, we think the re-frac opportunities across our Haynesville portfolio are significant and can help offset PDP declines. We have an inventory of over 400 PDP wells to potentially re-frac, and we're excited about the early results that we and our partners are experiencing. We're working on a plan to test different re-frac designs to optimize cost and production in '14, with plans to implement re-frac campaign in 2015.

In the East Texas Shelby area, we have 16,600 net acres, with more than 70 wells flowing to sales at quarter end. We're wrapping up the drilling portion of our longer lateral 2014 Shelby test program as we finish drilling our eighth well. We like what we've seen from the 2 Shelby wells that were completed under new completions program with increased profit for completed foot and a more restricted flowback focused on pressure management. We're encouraged by the results of the 2 wells, with initial production rates averaging 9.9 million cubic feet per day on restricted chokes with an average 8,335 psi flowing casing pressure. With this revised flow back, we're significantly flattening our declines. We anticipate this program will add reserves in excess of prior forecasts. The results from this 8-well Shelby program will formulate the basis for our future manufacturing in this area where we have an inventory of approximately 290 drilling locations.

We continue to focus on our base production initiatives in East Texas/North Louisiana. We've seen a 6% gas production uplift on the 90 wells that we reduced line pressure on by 23%. Our next step in this process is interim lateral compression in Holly, which should reduce lateral pressures by a total of 40%. We're working closely with our midstream provider and expect to have lateral compression online in the third quarter, with full Holly field compression online in 2015. We also expect to have full field compression in Shelby in the third quarter of 2014.

We've also allocated capital to drill a test well in the Bossier shale in DeSoto Parish during the fourth quarter, and we'll use this well to assess the potential of the formation utilizing our enhanced completion techniques. The Bossier shale lies just above the Haynesville shale and contains rich deposits of natural gas. We drilled 2 Bossier wells in 2010, and we believe we can apply today's technology with newer completion designs and flow back methodologies and significantly improve on our results. We also believe we can significantly bring down the original cost of the Bossier wells with the efficiencies that we've gained over the last several years. This should increase the economic viability of a significant number of additional drilling locations.

The majority of the up to $80 million incremental capital, if we go forward with our spending would be targeted for East Texas/North Louisiana. The primary driver of the increase would be drilling 3 additional high-working interest sections we acquired in 2013, which could be turned to sales at the end of '14 and in early 2015 providing a significant jump start to our 2015 production levels. If we fully deploy the revised capital, we drill up to 46 wells in Holly in 2014.

Turning to South Texas on Slide 6. We have approximately 49,000 net acres in the Eagle Ford oil window, with farm-in options to earn additional net acreage. Our acreage is primarily held by production and also includes additional upside in other formations including Buda, Austin Chalk and Pearsall. We produced 534,000 barrels of oil in the second quarter as compared to 525,000 barrels in the first quarter. We drilled 21 wells and turned-to-sales 13 wells during the quarter in Eagle Ford and had approximately 170 wells on production at the end of the second quarter. We've realized average 24-hour initial production rates of 475 barrels of oil per day in the core area wells we turned to sales in the quarter, excluding 2 wells on the extreme far north side of our acreage.

To optimize our drilling and turn to sales timing, we reduced our rig count from 5 rigs in April to 3 rigs in May and June and went to 2 rigs in July. We continue to achieve improved drilling times per well and are currently averaging 13 days from spud to rig release, compared to 17 days during 2013 when we took over operations. Furthermore, we recently drilled wells here in under 11 days, with total measured depth of 14,500 feet. Based on these efficiencies, we can drill with fewer rigs.

Going forward, we'll be producing a majority of our wells into central facilities. These central facilities will reduce our total capital investment, improve operating efficiencies and minimize trucking. Two of these facilities are expected to be online during the third quarter, and we've built up an inventory of 23 wells that will be completing and producing into these facilities during that time. We'll focus on completing and connecting these wells, and we'll drill with 2 rigs until mid-September before we add a third rig back to the portfolio. Looking at our overall Eagle Ford program for 2014, we currently expect to drill 72 wells with 63 in the core area. Our non-core well count is going up to 9 based on our incremental capital expenditures, and these wells have higher EXCO working interest.

During the second quarter 2014, we reduced our shut-in volumes by 1/2 as we compare ourselves to the first quarter, as we have a continued focus on optimizing our drilling and completion schedules. Additional upside in South Texas includes the optimization of base production and the evaluation of other formations. We've installed 64 pumping units to enhance production since we acquired the South Texas asset, and we have plans to install an additional 47 pumping units during the remainder of 2014. Obviously, pumping units have very attractive returns with very short payouts.

Our evaluation of the 37,000 net acres that are prospective for the Buda formation is ongoing. We've recently seen strong results by other operators close by, and we're ranking our acreage for prospectivity and analyzing subsurface data and actual well performance. We're currently preparing to test the Buda formation on a portion of our acreage during 2014.

The map on Slide 7 highlights our broad acreage position in Appalachia. EXCO holds approximately 290,000 net acres, with approximately 145,000 net acres prospective for the Marcellus shale. With our 70% HBP position in the region, we control much of the timing of the development of our acreage. Due to regional price differentials, we've reduced our drilling program and now plan on drilling 1 appraisal well to hold acreage during 2014. This well will offset our most recently turned-to-sales well that has cumulatively produced 1.9 Bcf in just 9 months.

In addition, our base declines have been less than originally projected, mainly due to our performance in Lycoming and Sullivan counties, Pennsylvania. We recently restructured our field organization to better align the operations personnel with the asset base and reduce our operating costs. We like having Appalachian assets in our portfolio as they provide future optionality with nearly 2,000 drilling locations. Slide 8 summarizes the various initiatives that I've touched on that are ongoing across our portfolio, focused on our base production.

I would now like to turn the presentation over to Mark for the financial overview.

Mark F. Mulhern

Thank you, Hal, and good morning. I'm going to turn you to Slide 9, which summarizes the basic tenets of our financial strategy that we have executed on. Debt reduction and liquidity enhancement have received significant focus at EXCO, and with our current liquidity, we are well positioned for EXCO's future growth. With regards to our capital program, we continue to monitor the movement in natural gas prices as we evaluate our future activity levels. On the acquisitions front, our business development team continues to look at assets and transactions that are consistent with our strategy.

Taking you to Slide 10. You can see our second quarter performance as compared to guidance. Adjusted EBITDA outperformance was primarily driven by better-than-forecasted oil production with lower shut-in volumes along with slightly better gas production. Our operating costs also came in lower than forecast with our continued focus on cost management. While actual general administrative costs came in higher than forecast, that includes about $2.2 million of one-time costs related to a workforce reduction.

As we have outlined in our production guidance on Slide 11, the timing of when wells are drilled and turned-to-sales impacts the quarterly numbers, but does not materially impact our full year expectations. Additionally, third quarter oil production will be impacted by the timing of wells coming online, as Hal outlined. Average daily production is expected to reach the low point for the year in the third quarter at the guidance midpoint of $362 million cubic feet equivalent per day based on the drilling completion schedule for the remainder of 2014. In aggregate, we are forecasting an adjusted EBITDA range of $90 million to $95 million for the third quarter. We are also reaffirming our full year adjusted EBITDA range of $400 million to $425 million. Our guidance is based on a $3.97 price for natural gas and $100 for oil in the third quarter, and $4 for natural gas and $90 for oil in the fourth quarter. As you know, EXCO maintains an active hedging program to facilitate the execution of our development plan. It assists in managing our liquidity and helps protect our downside exposure to commodity prices. For the second half of 2014, expected production approximately 67% of NATGAS and 87% of oil are subject to swaps at average prices of $4.22 and $95.70 respectively.

Regarding the participation agreement in the Eagle Ford, the pace of turning wells to sales has been a little slower than we expected. Our previous illustrative example of tranches of 20 to 25 wells eligible for offer per quarter starting in the first quarter of 2015 could shift 1 quarter or 2 based on the timing of when these wells are turned-to-sales. This shift will likely result in less capital from EXCO for Eagle Ford purchases under the participation agreement in 2015. We expect to provide more specifics on the tranches of wells and the timing of projected purchases when we outline our guidance for 2015 later this year.

Slide 12 has our cash, debt and liquidity at June 30. We used the proceeds from the $500 million unsecured notes issuance in April to pay off the $298 million term loan and a portion of our revolver. We believe approximately $740 million of liquidity provides a solid flexibility for the quarterly offer process in the Eagle Ford beginning in 2015.

Before we take your questions, and in closing, we have demonstrated through our actions that we are executing on our strategy and delivering on our commitments. We have a clear growth pipeline supported by a significantly improved balance sheet and stronger liquidity. We believe our continued focus on successful execution will result in increased value for our shareholders.

So thank you for your time this morning. Now Hal and I will open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Will Green from Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we could start on the re-frac opportunity you guys talked about. The $1.2 million a day uplift you guys are seeing. Can you talk about what that production profile looks like beforehand? And has it resumed kind of a predictable decline at this point to where you guys have any early estimate as to the EUR uplift on something like that?

Harold L. Hickey

You hit on the point. Will, it is very early. This thing has only been online for about 3 weeks. Now we saw it go up dramatically. We were at 550 mcf a day and it went up to about 1.85 and the well literally is still cleaning up. The water volumes are continuing to come down. The pressure's held up very strong. But it jumped from what, 1,300 psi to about 4,200 psi. So very encouraging results and, again, some refinements needed on our design. We'll continue to look at that. One re-frac does not define the way the program is going to be going forward. We're actually going to try a very different design on the second re-frac where it's on a different type well that hadn't performed that great. This well in particular had cubed about 4.85 Bcf. The second well we're going to re-frac is going to be much more of a skin frac, and it's only cum-ed about 1.8 Bcf over a similar timeframe. So it hasn't performed nearly in the same way. So we're testing the program. Now until we get 3, 4, 5, 6 months data, we're not going to sit here and tell you what we think the reserves booking are going to be. It's just too early for that, and perhaps we're conservative, but that's our approach.

Will Green - Stephens Inc., Research Division

Got you. I appreciate all that color. And what's kind of a typical cost to expect to see you guys spending on these re-fracs?

Mark F. Mulhern

Depending on what type re-frac we do. This one we actually did a little extra science on, running some logs, getting the well ready and making sure it was the right thing to do. We spent $1.7 million, $1.8 million on this one. I think future similar re-fracs we could bring down by $300,000 or $400,000. Now these skin fracs, I think you could do them closer to $1 million to $1.1 million. So again it depends on the design. But the cost range, depending on what type you do, is from $1 million to $1.1 million, up to $1.5 million, $1.6 million.

Will Green - Stephens Inc., Research Division

Got you. And then, I'm not sure if you mentioned it, but what kind of cost reduction are you guys seeing in the Eagle Ford due to this reduction in drilling time and spend less time on the [indiscernible]?

Harold L. Hickey

Yes, originally we were at $7.2 million when we took over operations on the last conference call. We were down to $6.9 million. I forgot to mention that we're actually at $6.8 million today and actually still see some efficiency improvement opportunities. So it's continuing to creep down and I will color that with the fact that we are seeing some upward pressure from some of our service providers on cost, in particular fracture stimulation costs have gone up, probably on the order of 8% to 10% per stage. And so factoring that in, we've still been able to bring our costs down. But it's not as much as we would have thought had service costs stayed flat, if you will.

Operator

Your next question comes from the line of Michael Rowe from TPH.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I'm just wondering, thinking about your Eagle Ford program, obviously, you have the 50% reduction shut-in volumes in Q2 relative to Q1. I'm sort of wondering how, I guess, the shut-ins in Q2 compared relative to your original guidance. Just thinking about how that really impacted your Q2 results, and whether or not well performance is actually better-than-expected in your core area?

Harold L. Hickey

The well performance in the core area has been about as anticipated. I would not say it's better. I would say it's coming in line with our expectations. As far as the guidance, I'll defer to Mark and Chris on that color.

Christopher C. Peracchi

Michael, it's Chris Peracchi. The downtime came in a little bit better and that's why you saw a pretty much most of that oil beat.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, great. That's helpful. And I was just wondering, could you maybe clarify what your current profit volume is on a per well basis in the Eagle Ford and whether or not do you have any plans to modify this or test upside frac jobs in the future?

Harold L. Hickey

Yes, we've got that. Bear with me for just a second. Total profit per stage in the Eagle Ford is about 400,000, okay? And then we're always continuing to modify our designs and, Harold, do you want to add some color on what sort of volumes we're looking at there?

Harold H. Jameson

In the Eagle Ford, as Hal mentioned, 400,000 pounds per stage, that's our typical design. That's our most common design that we're currently pumping. We have on a larger-job size basis, we've been to up about 525,000 pounds per stage. That's kind of the higher end. That equates to about 1,640 pounds per liter foot. So those are early, we don't have a lot of data with the wells with those larger job sizes but that's kind of the range is kind of where we've been to date.

Operator

Your next question comes from the line of Leo Mariani from RBC Capital.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Can you talk a little bit more about the $80 million in CapEx? Is there a certain gas price you guys are looking for on the forward curve to lean, to start spending more money here?

Mark F. Mulhern

Yes, Leo, I would not tie it necessarily, specifically to a targeted price. I think, as Hal outlined in his comments, we, like many others, had a thesis that refilling storage was going to be a bit challenging here. Obviously, we've had a cooler than expected summer across the country and we're clicking along here. It looks like that may not develop. But so in June, we went back to the board and outlined a plan where we would spend a little more capital here. I think we're now sitting and reevaluating that plan given the context that what's happened with prices. But again, we're trying to balance all of the equations here, and that is what's the return on capital obviously, but also trying to get some production growth going into next year and doing those things. And you know how this works, you got rig fleets and contracts to manage and people to deploy. It's just not snap your fingers and kind of turn off the water. So I think that the idea here is what you're hearing in our comments is that we've got some flexibility and we're going to, obviously, look to deploy capital as efficiently as we can, all again with an eye on balancing kind of production growth, returns and keeping an eye on the forward strip. I mean, we still think obviously, that you know how this works, seasonality happens here, as we get into fall and winter, we may see some firmer prices and that will dictate a little bit of what we do.

Harold L. Hickey

Let me add a little more color to that. You might have seen a slide we put out in the public domain before, Leo, that says in our Holly Area, at $3.35 flat pricing NYMEX, we can actually meet our internal hurdle rates. In other areas it's $3.75 going up to $4.25. So we're going to be selective on where we drill. Like Mark said, we're going to make sure we balance between what's the right thing to do growth-wise, what's the right thing to do on our balance sheet, what's the right thing to do from your guys' perspective as well. So it's a balance there but we can drill very, very economic wells at the current prices today and we are doing so. Our operating team continues to be able to bring these things in at AFE or below and in turn we're meeting the hurdle rates that we want. So in the mid-$3 range, we could definitely drill a number of economic wells. We still have a number of locations in our portfolio that will allow us to do that.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. That's helpful. And I guess, maybe just jumping over to you all's comment on your biz development team continues to look at acquisitions and opportunities. Can you guys elaborate on that at all? Are there any specific areas that you guys are targeting, and may either be something in combination with your JV with Harbinger that you're looking at? Or is this more EXCO looking at opportunities? Just any color you had around that would be helpful.

Mark F. Mulhern

Yes, I mean, I think it's fair to say no -- not surprising to anybody who follows the company, obviously, Haynesville and Eagle Ford are our areas where we're spending drilling capital and have activity. Marcellus we have, obviously, a good position there as well, but not very active there from a drilling and exploitation perspective. So I would say, we have at the EXCO level, been interested in those 2 areas: Haynesville and Eagle Ford and have looked at a number of opportunities. On the MLP side, they have been very active in a lot of the sale processes and we've obviously been involved with that as well. So nothing directly to report. But the MLPs focused on these conventional assets, long-lived shell decline kind of asset packages and they've been very busy with what they're doing. So that's what I would say our business development team's been focused on.

Stewart Glickman - S&P Capital IQ Equity Research

Okay. And I guess, in terms of Eagle Ford, I think you guys had drilled some step-out wells, this quarter. It sounded like in your prepared comments that maybe they weren't as good and you guys pulled some of those out of the average. Can you just talk about what you guys are thinking on some of the step-out acreage here at this point?

Harold L. Hickey

If that's the message that we conveyed, I apologize for that, because some of the step-out wells have actually been very, very strong and in turn that's why we're actually increasing the number of wells we're drilling outside of the core area. Particularly to the East, we've been excited about some of those results, and I don't want to give a whole lot of disclosure around them because it's still an evolving play and we may want to lease some more land out there. But the bottom line is we like it, and it's been a very positive result for us.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to follow up on the CapEx question just to be clear, crystal clear that the budget has gone up, or you've gotten the permission to increase your budget by $80 million, if these commodity prices hold both on the oil and natural gas side, would you expect to increase your budget? And what within that $80 million would that be?

Mark F. Mulhern

Well, again, Brian, to be very specific about what Hal said in his comments, and what you see on the guidance slide, is we've adjusted the guidance to a $400 million to $440 million range from $368 million. So think about that on the low side, $30 million, high side $70 million. And again, what we said in our remarks is we're looking at the plans and what our strategy is around rig deployment and try to balance again some of these objectives together. So I don't -- I would say we're evaluating those numbers. I don't expect we'll spend all the way up to that $80 million, but we will spend some of it. So I mean, I think that's how you should think about it.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, great. And then just bigger picture, can you just talk about the key leverage metrics you use when evaluating CapEx and the potential for CapEx increase or a greater capital allocation, as you go forward?

Mark F. Mulhern

From a financial perspective, we're obviously keeping our eye on liquidity. We've got the normal debt-to-EBITDA covenants and the revolver package and all that. So we're mindful of all that. We keep that obviously, at the forefront when we're thinking about hedging. So when we think about pricing and what our expectations are, we obviously do some downside thinking around what our covenant requirements would be. But then on the other side of this, obviously, it's evaluating liquidity and what we deploy capital to in relationship to kind of growing production, growing EBITDA as the company moves forward. In 2015, as you know, we've got the Eagle Ford buyback packages starting with our participation agreement with KKR. So we've got some, we think some clarity around some growth opportunities in '15 but we're also thinking that some investment in further exploiting our properties can help us with some growth objectives for 2015 and beyond.

Brian Singer - Goldman Sachs Group Inc., Research Division

And do you think about the KKR Eagle Ford acquisition as spending as replacing a portion of your CapEx budget this year when you think about next year? Or is that all incremental? In other words should we think about the base case level of activity as flat to up in 2015 and then you add on the Eagle Ford acquisition spending beyond that? Or does one replace another?

Mark F. Mulhern

So it's early, right. We haven't given any real visibility around that but I would say it's mostly incremental. I mean, the CapEx budget could be balanced a little bit with it, but I think it's mostly incremental.

Operator

Your next question comes from the line of Yanni Jacobs [ph] from Chart Topics [ph].

Unknown Analyst

I appreciate your efforts to improve the operations, reduce costs, increase profitability. The main reason why I'm investing in ESCO is because I really believe that natural gas is -- has begun a long-term bull market. And I think that even though you guys have debt and, I guess some investors view financial statements as troublesome, I think that natural gas prices going up in the future would help the company. So how do you guys -- going forward, I know you're hedged, but assuming prices go up, how would you take advantage of those rising NATGAS prices in terms of either hedging or improving the financials?

Mark F. Mulhern

Yes, I mean, obviously, we're sitting at this table because we have the same belief that you do. So in our view, on a long-term basis, we do think natural gas prices will be positive. And our view is, we're obviously mostly a dry gas company with our positions in the Haynesville and up in the Marcellus. We believe we've got a lot of optionality going forward. I think if you look at some of our slides where we've indicated the number of drilling locations and what the economics go around, what prices indicate reasonable returns and those, we've got a lot of inventory. So our view is we've got a lot optionality in the company around your -- what you believe around prices. And I think that the hedging question is one of balance, right? You've got a leveraged package here at the company that we, obviously, have to be mindful of and we have generally been looking 1 year out pretty well hedged, 1 year out. Again, going into '15 we're probably a little less hedged than we normally have been. At this point, I think our liquidity position, our improved liquidity position has given us some flexibility around that. But we're in your camp and with respect to being bullish in the long term.

Operator

[Operator Instructions] Your next question comes from the line of Michael Rowe from TPH.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I will jump in here again, if I can. Just wanted to think about kind of looking at your Q3 gas guidance and what would kind of be required in Q4 to hit the low end of your gas guidance for the year. It looks like you may need to, if you have a 4% quarter-over-quarter decline in Q3, you may have to be more flat kind of in Q4 to hit the low end. So I'm just wondering, is that a function of fewer completions in the first half of the year and then more completions weighted towards the second half of the year, that kind of helps those gas volumes pick up.

Mark F. Mulhern

Yes. There's no question that if you look in -- if you think about our guidance that we gave at the beginning of the year, you go back and kind of look at what we said, we said we were going to -- we thought we were going to be back-end loaded on turned-to-sales, especially on the gas side of this thing. So yes, we have -- I'm looking around the table here at our operating team. We've got some goals and we told you Q3 is kind of be -- going to be the low point in terms of production. We've got some delivery to make in Q4, there's no question. But again we're very confident about our abilities to do that. We've got a good team and a good operating relationship with our contract crews. So yes, but Q4 will be important to us in delivering on the full year guidance, no question.

Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. That's helpful. And I guess, just a last question from me would be, you're talking about some new completion enhancements that you're trying in the Shelby area. And then with the new Bossier test well later this year, you want to try a couple things new relative to some of the wells in 2010 that you drilled and completed. So would you mind just providing a little bit more context on kind of what the baseline is for each of those areas and where you're going to on the completion design?

Harold H. Jameson

Starting with Shelby first. Looking at the Shelby area, one of our main drivers in the Shelby area is really to improve our prop per foot, our job size. We've increased our job size in that area and then the rate restriction in the Shelby area is going to be important. We've discussed the results of the first 2 wells. They're pretty early on but it's very encouraging. We're managing the pressure profile there. So that is the single largest change we've made down in the Shelby area.

Harold L. Hickey

On the laterals.

Harold H. Jameson

And the lateral links are longer as well. That's a third component at Shelby. When you look at Bossier going forward, the Bossier data we have up in the Holly area is really, as Hal mentioned, dated back to 2010. So we've learned a lot since 2010 over the last 4 years on just completion evolution. So what we want to do is essentially apply everything we've learned on the completion side, the design side itself. The cluster spacing has changed over that period of time. And then going forward, the rate restriction we think is really important.

Harold L. Hickey

In 2010, when we drilled those Bossier wells, we frankly, flowed them back too fast. We opened up the choke too much. We had a restricted choke program but we went up to probably 28, 30, 64s. Now we had limit that dramatically and managing that flow back, we think will help preserve the integrity of the reservoir. And in turn we think that we'll be able to add some EUR to what we originally forecasted in the Bossier. Also, you can't discount the fact that we've bought our costs down dramatically since that time. We were spending nearly $10 million -- $9 million to $10 million a well at that point. We think we can get these Bossiers drilled now for probably $7.5 million to $8 million, $7.5 million to $8 million. Go ahead, Mike.

Michael R. Chambers

We have stronger laterals too.

Harold L. Hickey

Yes.

Michael R. Chambers

With our development section, we can, probably almost probably half or more than half, we can do long laterals.

Mark F. Mulhern

Mike, I think the way you're -- obviously, you asked a very specific question and I think you got some color. But if you look at Slide 8 in our slide package we've put out with the earnings release, I think you see a number of different initiatives that the technical and operating team here are working hard to deliver on, and I think we've got some -- we're excited about the possibilities of a number of these things and some of the things you've hit on the call today, the re-frac opportunities, some of these line pressure things, some of these other things that opportunities and to explore other basins. And again, apply some of the learnings that we've had over a long period of time of drilling out the Haynesville, in particular, I think we're optimistic that we've got some really good levers to pull here that can help us stabilize the production decline and add value for the company.

Operator

Your next question comes from the line of Owen Douglas from Baird.

Owen Douglas

Just wanted to ask a little bit about your guidance with regards to the oil production in particular. We only have 2 quarters left and just looking at what you gave for Q3, Q4 sort of implies that Q4 is going to be a meaningful decrease in the way of production. Can you speak to whether that's just a little bit conservatism, being that far out? Or is there something that we should be factoring in, in our modeling?

Christopher C. Peracchi

Owen, this is Chris Peracchi. From looking at the numbers correctly, you actually will see the -- based on the completions that Hal had touched on, the oil production kind of sequentially migrating down a smidge and then you see it picking back up again in 4Q to get to the total number for the year.

Owen Douglas

Okay. I'll sort of refresh the model and make sure I'm okay with that. And just wanted to also ask a little bit about that, those Eagle Ford assets with KKR. Can you sort of give us a bit more color in terms of what's the pushback, the completion rate there? And how we should think about the asset purchases? Will it be absolutely none in first quarter 2015 and everything moved over to second quarter? Or I mean, how should we think about the pacing on those acquisitions?

Harold L. Hickey

First, let me address the central facilities and then Mark can talk about the KKR buybacks. We decided to go to a central facility concept for multiple reasons, as I outlined in the comments earlier. But in particular, these central facilities reduce capital significantly for us. And they minimize truck traffic and it gives us the central location from which we can treat facilities. And it's actually going to reduce some of our cost particularly on the trucking side and on the transport side. In turn, those things are delayed about 1 month beyond what we originally thought they're going to be turned on at. So they're going to come online between August 15 to 22, is the first one and the second one should come on in September. And we delayed completing some of those wells that we don't put well site treating facilities on until those central facilities come on. So it's simply a matter of timing. It has nothing to do with our operation efficiencies or service providers. It's simply timing. We're awaiting the installation and startup of the central facilities.

Mark F. Mulhern

So let me then connect the dots to the relationship with our participation agreement with KKR. So the concept of turned-to-sales is a very important one in the agreement. If you recall how this works, is the clock effectively for our obligation to make an offer to buy them out is -- revolves around turned-to-sales. So you can drill these wells. If they're sitting there and they're not turned to sales, the clock hasn't started. So that's why I'm giving you a little bit of caution around the timing of when these happen. So no, I do not -- to your question specifically, no, I believe there will be an opportunity for us to offer on some wells in the first quarter of '15. It may be just less in number. If you remember the illustrative example we gave was we thought 20 to 25 wells would be in that first tranche. That may be a lower number. Again, partially because of this central facilities issue that Hal has talked about. So I'm expecting just a push out in time and I -- what I would expect us to do as we get closer to the end of the year, give you very detailed -- our detailed expectations of what we think those tranches might look like for 2015. And I'd then, the only last comment I'd make, is I think what this means is, there's potentially less buyback capital in 2015 for us. In other words, we -- I think, we will have to fund less buyback capital in '15 above our regular CapEx. That, obviously, also has implications that in production and adjusted EBITDA, but again we'll give you that picture when we're ready to do that. But that's what I wanted to just indicate in my comments.

Operator

Your next question comes from Ted Lieu [ph] from Valley Financial Group.

Unknown Analyst

Just a quick question. Are you using any downhaul micro-seismic on your re-fracking processes?

Harold L. Hickey

Yes, we are. We use micro-seismic, and we use it to analyze some of our programs.

Michael R. Chambers

We didn't use it on this particular re-frac, if that was the specific question.

Harold L. Hickey

But we do use microseismic.

Michael R. Chambers

Yes.

Harold L. Hickey

Across our portfolio particularly to understand what's going on in the rock as we frac wells and such. But on the re-frac, we didn't use it on this instance but we've used it most recently down in Eagle Ford.

Operator

And I have no further questions at this time. I turn the call back over to our presenters.

Christopher C. Peracchi

Thank you very much for your interest in EXCO. This concludes our second quarter earnings call.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!