EXCO Resources Management Discusses Q1 2014 Results - Earnings Call Transcript

Apr.30.14 | About: EXCO Resources, (XCO)

EXCO Resources (NYSE:XCO)

Q1 2014 Earnings Call

April 30, 2014 10:00 am ET

Executives

Chris Peracchi

Harold L. Hickey - President and Chief Operating Officer

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

John D. Jacobi - Vice President of Business Development

Analysts

Brad Heffern - RBC Capital Markets, LLC, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Howard Henick

Jeffrey W. Robertson - Barclays Capital, Research Division

Operator

Good morning. My name is Courtney, and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Schedule First Quarter Earnings release and Conference Call. [Operator Instructions] Director of Finance and Investor Relations and Treasurer, Chris Peracchi, you may begin your conference.

Chris Peracchi

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

With us today, in addition to Hal and Mark, are other members of the EXCO management. Since much of our remarks today will contain our expectations for the future, they are subject to numerous risk factors, as elaborated upon in our 10-K and other filings. These comments constitute forward-looking statements within the meanings 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. Good morning. Thank you for your interest in the EXCO Resources Conference Call to Review the Results for the First Quarter of 2014. EXCO's transition to an execution focused, more predictable, easier to understand entity is well underway.

First, let's follow up on the macro thoughts we discussed on our last earnings call back in February. With the coldest winter in North America since the early '80s, EIA storage levels bottomed at 822 Bcf at the end of March, the lowest levels since 2003. Storage is currently at 900 Bcf or so, 48% below last year's level and 53% below the 5-year average. As we move further into the injection season, our contrast are currently low storage levels with only 310 or so land-based rigs drilling for natural gas, covering near to lowest levels since the early to mid-'90s. Combining these near term data points with longer-term expectations for growth in natural gas demand, from power generation, manufacturing and petrochemicals, exports to our neighbors and LNG exports, we believe our positive outlook for North American natural gas prices is reinforced and with great opportunities for EXCO going into 2015 and beyond.

Slide 3 provides the key takeaways from today's call regarding our first quarter results. EXCO delivered solid results ahead of guidance, as we continue to focus on operational execution and enhancing our liquidity. Our $500 million senior unsecured notes issuance in April reduced our secured borrowings and added length in term to our capital structure. We remain focused in 3 strong shale positions, and have an experienced operating team with a demonstrated ability to improve efficiencies and drive down costs. With that continued success in the Eagle Ford, we're bullish on the prospective quarterly purchases from our drilling partner. These purchases will begin in 2015. We're very confident our stronger balance sheet and liquidity will facilitate these acquisitions and anchor EXCO's growth.

Turning to the highlights on Slide 4. Yesterday, we announced results for the first quarter that exceeded our expectations. Adjusted EBITDA of $112 million exceeded the high end of guidance. Production for the quarter of 407 million cubic feet equivalent per day was above the midpoint of our guidance, and was driven by oil production of 593,000 barrels. In addition, we reduced debt by $630 million over the past 6 months, so now we have about $790 million of liquidity. We continue to demonstrate fiscal discipline, with capital expenditures coming in below our adjusted EBITDA. Thanks to our employees and contractors, we drove 36 and completed 15 wells in the quarter, and continued to operate safely and in compliance with rules and regulations.

On Slide 5, you can see 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 core Holly area in DeSoto Parish, Louisiana, and 2 rigs focused on appraisal, testing and delineation in the Shelby area of East Texas. We drilled 13 wells and completed 2 wells in the quarter. As a result of our manufacturing designs, which include multi-well pad drilling and completion operations, we had 10 wells waiting on completion at the end of the quarter, and we have already begun turning them to sales.

Our core Holly position includes about 30,000 net acres in DeSoto Parish, Louisiana, where we had 358 wells flow into sales on 42 developed units at quarter end. For 2014, we're developing 7 of our 36 undeveloped units, drilling 34 wells in the Holly area. We've initiated drilling operations on our first cross unit development in DeSoto Parish, that includes drilling 5 wells with 5,000 to 8,000-foot laterals. For this particular drilling, cross unit development provides us the opportunity to horizontally drill into a unit that we would not have previously drilled, as it has a fault that bisects the unit. With the improved regulations in Louisiana, we are able to drill across unit boundaries, contact more horizontal sections with longer laterals from a single wellbore. Of course, this results in additional recovery and improved economics.

We're planning the operational skills we developed in Holly, as shown on Slide 6, to manage drilling and completion design, scheduling and costs in Shelby. We'll resume drilling in the first quarter. We have 16,600 net acres in the Shelby area, with 70 wells flowing to sales at quarter end. We plan on drilling 8 wells in 2014, with longer laterals up to 7,000 feet, increased profit for completed foot, and more restricted flowback. The results from these 2014 program will formulate the basis for future manufacturing in the Shelby area. We plan for this to provide a growth platform for EXCO as we have an inventory of approximately 290 Shelby area drilling locations for future development.

We're encouraged by the early results of our base production initiatives, including reducing the gathering line pressure from 1,250 psi to 900 psi in a portion of our Holly field. The initial results for the 40 or so wells included in this test show an 8% to 10% production uplift as a result of the reduction in line pressure. We're also adding artificial lift and we're studying both interim lateral compression and full field compression options to enhance our base production efficiency.

Following up on our discussion from last quarter, we've included our DeSoto core Haynesville top curve on Slide 7. With our 2014 budgeted $7.5 million drilling completion capital, and a 6.9 Bcfe bar [ph] which has been prepared by a third-party engineer, we forecast 48% wellhead rates of return based on year-end strip process in the table, which are lower than the current strip. The upside in returns with higher gas prices and lower drilling completion costs is shown on the smaller graph on the right of the slide. For example, with a $4.50 strip, you have a high 60% rate of return. The green line in the curve documents the performance of the wells drilled on 6 wells per section that returned to sales in November of last year. As we discussed on the last call, we're now manufacturing based on 6 wells per section, as this optimizes our economics on a per well and per unit basis. With our ability to manage drilling and completion costs, we can generate higher rates of return and realize a better section economics versus spending additional capital on an incremental section well.

As you can see on Slide 8, we have a significant drilling inventory, with over 1,200 identified drilling locations in East Texas, North Louisiana. At a flat price depth of $4.25 and our current cost, about 6 of these locations generate a 20%-plus bt rate of return.

EXCO has 14 years of economic drilling inventory based on our current drilling base of 42 wells per year and this $4.25 price deck.

Turning to Eagle Ford on Slide 9, we have approximately 48,000 net acres in the oil window, with 4 main options to earn additional net acreage. Our acreage is primarily held by production and also includes additional upside and other formations including Austin Chalk, Buda, and Pearsall. We operated 5 drilling rigs during the first quarter, focusing our core area in Zavala County, Texas. We drilled 23 wells and completed 13 wells during the quarter. We realized average 24 hour initial production rates of 480 to 490 barrels of oil per day in the core area wells we've completed since July, which is in line with our 375,000-barrel type curve. Here, individual well economics provide rates of return in the mid-30s on a flat $90 oil price.

Our 2014 drilling program consists of manufacturing and testing in the core area, and appraisal drilling in the adjacent farm-out areas. We have budgeted drilling 90 gross wells, including 6 farm-in wells in the Eagle Ford.

In addition, our evaluation of the 37,000 net acres that are potentially prospective for the Buda formation is underway.

We've realized significant improvements in our drilling performance since we acquired the Eagle Ford assets, as shown on Slide 10. We continue to achieve improved drilling tasks per well and are currently averaging 13 days from spud to rig release, compared to 17 days in 2013. We recently drilled a well on 11 days with a measured depth of 14,000 feet, including a 7,100-foot lateral. There's no single reason for this improvement. Multiple enhancements, including bit selection, changes to our BOPs and centralizer program and, frankly, experience, all contributed to this improvement in drilling time.

During the first quarter, our shut-in volumes in the Eagle Ford ranged from 1,650 to 2,500 net barrels of oil per day, which we had factored into our first quarter guidance. These shut-ins were due to offset drilling, completion and maintenance activities. Managing shut-in volumes is an important factor as we have a higher working interest in the PDP wells we purchased in the Eagle Ford acquisition, when compared to the wells being drilled under the participation agreement.

Our shut-in volumes will decrease over time as we optimize our manufacturing low drilling and completion activities with our production activities. This directional decline of shut-in will have some ups and downs, quarter-to-quarter, due to our drilling completion schedule. Our net shut-ins are currently down. Our April shut-ins have ranged between 1,000 and 1,500 net barrels of oil per day. But we do expect some continued ups and downs on these volumes.

Finally in the Eagle Ford, we're performing microseismic analysis that will provide additional data to help us with our decision-making and management of shut in volumes, spacing and frac design. We're also implementing initiatives to optimize and increase the efficiency of our oil production. We installed 24 pumping units on producing Eagle Ford wells during the quarter, and have plans to install a total of 90 pumping units during 2014. Over the first 40 days after installing artificial lift, we've averaged 21 barrels of oil per day of net uplift per well. This investment in rod pumps pays out in about 2 months. In order to reduce transportation costs and production expenses, we've contract with a third-party to design and operate oil and water gathering lines, central production facilities and an oil pipeline from our core area. We expect to have our first central facility operational during this year.

The map on Slide 11 highlights the broad acreage position we have in Appalachia. EXCO holds about 290,000 net acres, with approximately 145,000 of these net acres prospective for the Marcellus shale. With our 70% HBP 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 in this region and plan on drilling 2 appraisal wells during 2014. Our Appalachia production has been relatively stable. It was marginally impacted by the challenges of the cold winter that caused higher than average downtime due to freezing conditions. We've had strong results on our recent wells turned to sales, with our most recent well IP-ing at 11.3 million a day in late '13. This appraisal well is currently flow in 7 million cubic feet per day on a 1,400-psi restricted choke. I'd now like to turn the presentation over to Mark for the financial overview.

Mark F. Mulhern

Thank you, Hal. And good morning. I'd like to turn you to Slide 12, which basically summarizes our financial strategy we've been executing. We made tremendous progress in debt production and liquidity enhancement, and that's received a significant focus at EXCO. With our current liquidity, we are well-positioned for the Eagle Ford purchase program, beginning in 2015.

With regards to our capital program, we continue to monitor the movement in near and long-term natural gas prices, as we evaluate our future activity levels. While we remain committed to managing our capital spending, we will consider additional rigs if the economics make sense. On the acquisition front, our business development team continues to look at assets and transactions that are consistent with our strategy and are appropriately sized by our organization in our balance sheet.

On Slide 13, you can see our first quarter performance as compared to guidance. So we had a solid quarter. Adjusted EBITDA performance was primarily driven by better than forecasted oil production, as we turned to sale as more wells than initially budgeted. Our operating in general and administrative cost came in -- also came in lower than forecast, and these positives were partially offset by lower gas production and price realizations.

As Hal mentioned, we had 10 wells waiting on completion at the end of a quarter, and as we've indicated on a prior call, the majority of our expected wells being turned to sales for 2014 occur in Q2 and Q3, with the first fully developed Haynesville unit already having been turned to sales.

Our second quarter gas production guidance on Slide 14, reflects this completion timing in Haynesville, along with shut-ins for completion activities. It's an important point. We did give you some guidance that our quarterly performance would be influenced by timing of when we drill and when we bring things to market here, so I think it's really important when you look at our guidance to consider that. So our second quarter oil production will be impacted by the shut-ins we've previously discussed, and our average daily production is expected to reach a low point for the year in the second quarter and then improve from there. So the guidance is 375 million cubic feet equivalent per day based on the drilling and completion schedule for the remainder of 2014.

In the aggregate, we are forecasting an adjusted EBITDA range of $90 million to $95 million for the second quarter. Again, we think that's a low water mark for the year. So for the full year, our adjusted EBITDA range is based on $4.33 for natural gas and $96.67 for oil in the second quarter. And then we've gone to a flat $4 for natural gas and $90 for oil in the third and fourth quarters; recognizing, as Hal said in his earlier comments that we're bullish, relatively priced to the rest of the year, for especially in gas.

EXCO maintains an active hedging program to facilitate the execution of our development plan, assist in managing our liquidity and help protect our downside exposure to commodity prices. So for 2014s expected production, approximately 83% of nat gas and 95% of oil are subject to swaps and calls at average prices of $4.24, and $96.48, respectively.

So Slide 15 is an important slide that you've seen from us before and as part of our debt offering. It has our cash debt and liquidity at March 31. We use the proceeds from the $500 million unsecured notes issuance in April, to pay off our $298 million term loan and a portion of our revolver. So again, we believe the $790 million of liquidity provides a solid flexibility for the quarterly purchases in the Eagle Ford beginning in 2015. And as a reminder, our rough estimates for those Eagle Ford purchases is about $50 million per quarter, or $200 million annually. So you can see with the liquidity we have, we're very confident in our ability to finance those purchases, again, going into 2015.

So in closing, we have demonstrated through our actions that we are executing on our strategy and delivering on our commitments. We have a clear predictable growth pipeline, and look forward to both production growth and adjusted EBITDA growth in the years to come. We have significantly improved our balance sheet and have strong liquidity. We believe our continued focus on successful execution will result in increased value for our shareholders.

So we appreciate your time this morning, now Hal and I will take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Brad Heffern.

Brad Heffern - RBC Capital Markets, LLC, Research Division

If you could give a quick update on the CEO search and how things are going there?

Mark F. Mulhern

Yes, Brad, good morning. It's Mark Mulhern. Not much new to report there. As we've said before, the governance committee of the board is actively working this issue. We have a search a professional search firm assisting them. There has been some activity, but really nothing to report publicly at this point.

Brad Heffern - RBC Capital Markets, LLC, Research Division

Okay, got you. Looking at the Haynesville and sort of the progress you guys have made on the line pressure issues during the quarter. I think that you guys lost something like 92 Bcf in reserves at year end '13, as a result partially of high line pressure. I was wondering if you can give some color around how much of that could potentially come back with the solutions that you're putting in place?

Harold L. Hickey

We think that there's a chance for -- not just a chance, a likelihood that a significant amount of those volumes will be recovered. It's not just line pressure, it's a combination of factors. But that said, I noted in the call that we were up to 6.9 Bcf on an EUR basis in core Holly. That was actually 6.3 Bcf at year end. So you can see we've already recovered that. Now we'll reiterate that, that number was prepared and endorsed by third-party engineers. So a lot of that recovery has already occurred. But we do not state reserves on a quarter-to-quarter basis.

Brad Heffern - RBC Capital Markets, LLC, Research Division

Sure, sure. Understood. And kind of along the same lines, there's a bullet that you have in the slide that I didn't hear you comment on in the prepared remarks, saying that 84, 2009 and 2010 Haynesville wells have produced over 76% there in the EURs.

I was wondering if you could provide a little more context to that. Is that saying that the amount of reserves that you're in for those wells were so low that they've already produced a significant amount of that this year? Or is that saying of the full 6.9 BCF numbers, 76% been produced?

Harold L. Hickey

I think what you're seeing thing there, you're onto something. What we believe is that traditionally, reserves are produce over time, and having that 76% already having been produced, at this point in time, gives us an indication that with the expected life of these wells, we have much more upside than we currently have booked.

Operator

Your next question comes from Brian Singer.

Brian Singer - Goldman Sachs Group Inc., Research Division

Just wanted to make sure, so we're clear on the trajectory of guidance and the impact of the shut-ins -- really on the natural gas side you talked about Haynesville, the Haynesville completion-related timing, can you quantify what that is in 2Q? And then how are you thinking about just what the normal course XT shut-ins type decline rate is? I'm just trying to juxtapose that with the trajectory of the implied second half guidance.

Mark F. Mulhern

So Bryan, here is how I would think about this. So if you lay the 2 slides next to each other, 13 and 14 from our slide deck, what you see is we were on the low end of production guidance for gas for Q1. And you see what we've done in Q2 for gas production, we've actually lowered that number. If you remember what we said was we were going to have, obviously, our decline curve in the Haynesville, and the timing of when we were going to drill in both the Haynesville and in Shelby, was organized around primarily having the turn to sales numbers happen in Q2 and Q3. So what you're going to see here is, we think, is the low point in terms of volume in Q2. And then as we turn to sales, our Q2 wells that we drill and our Q3 wells that we drill, we believe production in the gas side will increase in the third and fourth quarters. And that's kind of what reflected in the 12-month guidance. So if you see the 12-month guidance on Slide 14, you see that 123 that 131 effectively on gas. That's where we're guiding to. If you remember this is kind of what we said all along, that '14 was going to be a year of some flat to down in production. And then our anticipation is as we execute on the buybacks in the Eagle Ford in '15, we'll have an uplift in production and in adjusted EBITDA going forward.

Brian Singer - Goldman Sachs Group Inc., Research Division

Your expectation is that fourth quarter will also be above Q3? As opposed to just Q3 being a nice pop from Q2?

Mark F. Mulhern

Yes, it's up, or up slightly from Q2 -- or from Q3. Excuse me.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. And you've got this question many times, but as I figure, I'll ask it again. Just as natural gas futures have continued to push up here for '15, is there any contemplation of increasing activity in the Haynesville or the Marcellus?

Harold L. Hickey

We're always looking at the opportunities. We're going to maintain some discipline this year around ensuring that our development capital is within our EBITDA. That said, we are looking at some opportunities that could increase, by a slight amount the amount of activity we have in the Haynesville. We're also looking in Appalachia, probably not to increase the number of wells, but maybe to evaluate where is the best place to drill so when we get volumes online as opposed to only worrying about appraisal.

Operator

Your next question comes from Amir Arif.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Just a few quick questions. In the Haynesville, first of all, the line pressure on artificial lift that you're doing, the 8% to 10% uplift in production you're seeing on some initial wells, is that factored into your guidance in the second half?

Mark F. Mulhern

We have not really factored that into our guidance because we were obviously executing the program and wanted to see the results. So there maybe be some upside into the second half of the year guidance from that activity.

Harold L. Hickey

The only thing I'd caution is that there's going to be some timing involved in getting compression installed. So the likelihood of that having a significant impact during '14 is not big. It's more likely it will have a positive impact in '15.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay, so would you be with the lower line pressure then, I take it, you want the higher IP? Or would you just choke back the well a little more? Or are you comfortable with the choke back program you have?

Harold L. Hickey

We're comfortable with the choke back program as it stands. The IP would really have the biggest impact -- the biggest impact on the line -- the line flooring pressure lowering would be on the base production.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay, okay. And then in terms of well cost. You brought your well cost down quite a bit. Do you see those going lower by the end of '14? In terms of the $7.5 in the Haynesville, or the $7 million in the Eagle Ford? Or do you think it's...

Harold L. Hickey

Go ahead.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

I just want if you sort of hit a run rate now?

Harold L. Hickey

No, we always think that there's some room on a technical limit. We continue to challenge our staff to continue to look for improvements in both efficiencies and design. But as far as our planning goes, we're continuing to use the same numbers in our guidance as far as capital planning and budgeting. Am I optimistic in the Hayns, we might get a little bit more? Yes, but I'm not counting on it. But in the Eagle Ford, I'm a little more optimistic because it's real early days, if you will. I mean we've already operated it since August. We've taken out significant amount of cost. We dropped from $7.2 million to $6.9 million. Our only recently have seen some of these 11, 12, 13 day drill times. So I believe as we continue to operate there and we continue to evaluate both our designs, and we gain experience, I think there's some move downward that we expect there. I'm not going to put a number around it, but I do think it will move down.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay, and then just focusing on the Eagle Ford, the 90-yard wells that you're going to drill, can you tell us how many are in the core? And how many will be outside the core?

Harold L. Hickey

84 in the core. 6 are in the farming acreage.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Do you have -- you put out an IP on the core. Do you have IPs or average IPs, outside of the core? Is it...

Harold L. Hickey

Outside of the core, it’s been a wide range. And I would say that in some areas -- we've already drilled some wells there. We've been very, very happy and there's some well where we've identified areas where we will not drill. So it's a wide range. I leave it at that.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay. And then the Budapest. Is that coming in 2Q? Or is that the results, or is that more second half?

Harold L. Hickey

I'd say that's definitely second half of the year. We're evaluating it, we're looking at it with internal technical teams, we're also evaluating what's going on in the area with our peers or competitors, if you will. But it's a second half event for us.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay, and just one final question. So 11,000 or net acres in the core, the rest of acres, the 35,000, 36,000 acres that are outside of the core. Is there a timing on exploration? Or just given the well results you're seeing, or what should we be thinking about how much of that you'll continue to hold?

Harold L. Hickey

Most of our acreage is held in the core areas. So that's not an issue for us at all.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

And the 37,000 outside the core?

Harold L. Hickey

It's held as well.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

That's held as well.

Operator

[Operator Instructions] Your next question comes from Michael Rowe [ph].

Unknown Analyst

Yes just one question, certainly, back to the Eagle Ford. So it's not in these presentation materials. But in projection with the notes offering you all disclosed 375 Mboe type curve for the Eagle Ford. So is that supposed to represent what you all expect in the core area? Or is that representative of your entire acreage position?

Harold L. Hickey

That's the core area. That is definitely the core area type curve.

Unknown Analyst

Okay. And any initial thoughts on what the EURs is going to look outside of that? Or is that still too early to tell at this point in time?

Harold L. Hickey

Again, it's a wide range. It's very early, we've only drilled a minimal number of wells out there. We think that to the North, Northeast, we're very optimistic that there's going to be some good results there. I think that if you look in South, Southwest, I'm not as optimistic about it. But it's going to be a wide range. And I think some of it will be at or above the type curve average that we're seeing in the core, and I think some of it will be below.

Unknown Analyst

Okay, great. And then I just had one final question on the Haynesville. So the 8% to 10% production uplift, from the lower-end gathering line pressure. I just wanted to know, is that something that's also being actively tested by other operators in the play? And I guess from a macro point of view, what do you think are the potential implications to gas supply coming out of the Haynesville, if this becomes more widely used?

Harold L. Hickey

First, I'll say that some of the other operators because of their gathering systems and the systems that they go into, are actually operating at significantly lower pressures. We're probably on the high side at this point. So we've got some opportunity there. I don't see it as a big change on a macro basis from the whole area or the play. But I do think that we see some upside. There are some specifics, like I said, where we've seen people operating as low as 400 pounds in different sections of the play.

Operator

Your next question comes from Howard Henick.

Howard Henick

A couple of quick questions. One is, so you talk about hedging with calls, and I think that's kind of a misnomer. So how much of your hedging, particularly for gas, is calls versus swaps?

Mark F. Mulhern

There is a slide in the Appendix, on Page 20 of the Appendix of our presentation, if you want to refer to that, you can see the breakdown of the calls versus swaps that we have for '14 and '15.

Howard Henick

Okay. And the next question is, if you're bullish on nat gas, why would you use calls? Which again is not really a hedge, it's really just income in case it goes down. Why not use puts, spend the money, and leave yourself the upside while protecting you from the downside. If you really are bullish on natural gas prices, which I am -- but if you write calls, you're giving away the upside and still have a downside.

Mark F. Mulhern

Yes, these calls were entered into in 2012.

Harold L. Hickey

12.

Mark F. Mulhern

So we were about here in terms of just our view of the market and what we're doing here. So I would say, we'd be very much more consistent with what you’re thinking than we would be with kind of what we've done historically. So I just think you should watch for an evolution. I think there's 2 things that have happened for us at EXCO: #1, as you had commented, the macro environment for gas, we think it gets much better here; and the other thing that's happened is our balance sheet and liquidity is much stronger and much improved, and therefore we can, I think be much more opportunistic around what we do here, from the hedging perspective. And that's why we're preserving some upsides going into '15, that you will see us again, we will take action when we feel it's appropriate. But we really think there's going to be rising prices here and we want to be able to take advantage of that.

Howard Henick

And I apologize as I haven't had the chance to get that far into the Appendix, but what is the 2015 percentage hedged? And do you still have calls written then, or is that already done?

Mark F. Mulhern

Yes, as you see, if you will refer to Page 20, we have a very small amount calls out in '15. And we probably are somewhere in the neighborhood of 25%, 30% hedged for '15, somewhere in that neighborhood if you mix it all together.

Howard Henick

So you still -- a lot of it, you're predominantly not hedged in gas, at least. I mean, I have no problem hedging oil, I just don't understand hedging gas.

Mark F. Mulhern

I agree with you completely.

Operator

Your next question comes from Jeff Robertson.

Jeffrey W. Robertson - Barclays Capital, Research Division

Hal and Mark, can you all talk a little bit more about the cost trends in Eagle Ford. I'm just curious as to whether you're also seeing savings on the LOE side that go along with the capital cost savings that have an impact on the buyout economics that you all have shown in the press, in terms of what you think you'll have to pay, versus the PV-10 of what you'd be buying at the time the options are exercised?

Harold L. Hickey

First I'll address the cost structure then I'll let Mark talk about that PV-10 and the buybacks. But again, we do anticipate some improvements in cost, both on the capital side and the expense side. I think we've got a track record of that. We're transferring a lot of our learnings from some of our other plays, where we've had experienced down there. We're doing everything from getting our system and our virtual data room operational. It is operational now. We've actually hired a new production superintendent who is very experienced to go down there, get his hands on it. We've got some efforts underway. Like I mentioned in the remarks, about putting in a gathering system, some central facilities in oil transport line. We haven't really disclosed the number, but that could have a significant -- when I say, significant, I'd say double digit type impact on our transportation cost to move a barrel of oil. It also could have a significant impact on the cost to move a barrel of water. So we've got things heading in the right direction there. I think the pumping units are adding significantly to our production, so we've got a lot of positive things that are happening down there. We remain very optimistic from an operations perspective, that we're going to be able to improve our drilling completion and operations cost.

Mark F. Mulhern

So Jeff, the only thing I would add is, you've seen our illustrative example where we talked about the 23 wells and what we expect the kind of economics of the buyouts to be in '15. And I don't think we've changed that view very much. I would say that reduction in costs that Hal has talked about, in other words driving down the cost to drill a well is great for us, because we save $0.20 effectively on every $1 we spend. Because as you recall, the deal is, we got to get over 1.2x return on their capital, so the more we can reduce that number, the better off the economics are from EXCO's perspective. So I think, we're on path to deliver effectively those, the economics that we've illustrated in that example. And I don't think much has changed there. I think the operating guys are doing a really good job of managing cost. And Hal's right, the shared services that will help improve the cost over time for us and so we're optimistic about it.

Operator

Your next question comes from David Munson [ph].

Unknown Analyst

You've got a 375,000 barrel EUR in the Eagle Ford. How much of that is first-year EUR?

Harold L. Hickey

Well...

John D. Jacobi

24%.

Harold L. Hickey

About 24% of the production is produced in that first year.

Unknown Analyst

44%?

Harold L. Hickey

24%, sir. 2-4.

Unknown Analyst

24%.

Chris Peracchi

And we have about a 70% to 75% decline during the first year, and it produces about 24% of our EUR.

Operator

There are no further questions at this time. I will now turn the call back over to the presenters.

Chris Peracchi

Thank you for your participation this morning. And with that, we'll wrap up the call. Thank you.

Operator

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

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