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EXCO Resources, Inc. (NYSE:XCO)

Q4 2013 Earnings Conference Call

February 26, 2014 9:00 AM ET

Executives

Chris Peracchi – Director of Finance and Investor Relations and Treasurer

Harold L. Hickey – President and Chief Operating Officer

Mark F. Mulhern – Executive Vice President, Chief Financial Officer, Interim Chief Accounting Officer

Marcia Reeves Simpson – Vice President of Engineering

Analysts

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

Will Green – Stephens Inc.

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

Will Green – Stephens Inc.

Amir Arif – Stifel Nicolaus

David Martin Heikkinen – Heikkinen Energy Advisors, LLC

Steven M. Karpel – Credit Suisse Securities (NYSE:USA) LLC

Jeffrey Robertson – Barclays Capital

Operator

Good morning. My name is Charlene and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Resources Earnings Release Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you. Mr. Chris Peracchi, Director of Finance and Investor Relations and Treasurer. You may begin your conference, sir.

Chris Peracchi

Good morning, everyone and thank you for joining the EXCO Resources fourth quarter and full-year 2013 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 and full-year results. We will also provide some insight as to how we see our business evolving followed by a Q&A session. The supplement Hal and Mark commentary we have posted some slides through our website excoresources.com which you can access to follow on.

With us today in addition to Hal and Mark our other members of EXCO management, much of our remarks today will concern our expectation to the future their 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 Act, such forward-looking statements are subject to certain risks and uncertainties as disclosed by EXCO from time-to-time in it’s filing 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 statement.

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

Harold L. Hickey

Thanks Chris and good morning everyone. Welcome to the EXCO Resources conference call to review results for the fourth quarter and the full-year of 2013. As Chris mentioned, we posted a presentation slides on our website www.excoresources.com, and Mark and I will refer these slide number during our remarks.

Before we discuss EXCO’s results, I want to touch some macro and micro thoughts to frame today discussion. We believe the recent run up in natural gas prices on the front end of the curve will eventually manifest self itself in the back of curve.

We believe the market underestimates the rates of decline for shale gas and has not fully incorporated the impact of the shift to drilling rigs from natural gas oil. We expect demand for natural gas to increase in the future, which will drive natural gas prices higher and this will be a positive catalyst for EXCO. On a micro basis EXCO excited the year having enhanced our liquidity and reduced our leverage. We’re focused on three strong shale positions and have an experienced operating team with a demonstrated ability to continuously drive down costs and continuously improve performance.

With a positive start we have in the Eagle Ford we remain bullish on the perspective quarterly buyback that will begin in 2015 and we’re confident our stronger balance sheet and liquidity will facilitate these acquisitions and anchor EXCO's growth in 2015 and beyond.

Now we are as frustrated as many of you are with the current stock price, but we plan to continue our strategy of operational excellence, fiscal discipline and opportunistic growth to deliver results, we believe that value builds from core execution and that's our primary focus.

With that intro, let’s go through the presentation.

Turning to Slide 3, yesterday we announced results for the fourth quarter of that exceed our expectations. Thanks to our employees and contractors, we've had a strong operational quarter and drilled turned sales 26 wells it’s a total of 99 wells turned sales in 2013. Production for the quarter of 446 million cubic feet equivalent per day was above the midpoint of our guidance and oil production of 653,000 barrels for the quarter was above the high end of our guidance.

Adjusted EBITDA of $124 and $418 million for the fourth quarter and year respectively we’re above the midpoint of guidance, we focused on reducing leverage in between the right offerings and closed and pending divestitures will have reduced debt by $578 million from third quarter 2013 levels. We continued to demonstrate our fiscal discipline with capital expenditures covering in below the midpoint of our guidance and well below the adjusted EBITDA that EXCO generated.

On Slide 4, you can see that we effectively executed our 2013 goals as presented to you on the fourth quarter of 2012 call. The formation of the EXCO/HGI Partnership, in February enhanced our liquidity and put EXCO in position to acquire a $940 million of sale properties in July, establishing our oil presence in the Eagle Ford and building on our leading position in the core area of Haynesville. We diversified our portfolio through our entry into the Eagle Ford and established a platform for future growth with our drilling partner.

In November we sold TGGT our midstream company and received cash proceeds of $240 million, which help to further delever. And in January of this year we close the rights offering and raised $273 million with a support of our broad shareholder base and our principal investors. The proceeds allowed us to eliminate the asset sale requirement of our credit agreement six months ahead of the July 2014 requirement and help this pay down our revolver. On the operation side, our team drilled in terms of sales 99 wells and as of the end of 2013, we operate 7,863 gross wells represented 97% of our PDP reserves.

Our 2014 goals were presented on Slide 5, we continue to focus on efficiently developing our asset base and we are having solid results replicating our proven Haynesville efficiencies in the Eagle Ford.

Managing our balance sheet, maintaining ample liquidity remains a priority. Our current capital expenditure budget is well below the mid point of our adjusted EBITDA guidance of $413 million. We recently entered into an agreement to sell our non-operated West Texas asset for $65 million and we plan to use the proceeds to further reduce the borrowings on our revolver.

On the acquisitions front, our business development team continue to look at assets and transactions that make strategic sales for EXCO and are appropriately for organization and our balance sheet.

Regarding search for new CEO our board has engaged an executive search firm and that process is ongoing. While exact timing of when EXCO will announce the new CEO is challenging to predict, you can be sure the management team and the company remain focused on execution.

Slide 6 has some additional details on the pending sale of our non-operated West Texas asset. We recently signed a purchase and sale agreement with the private operator to sell the right interest for $65 million with the January 1 effective day.

Our net capital investments approximately $7 million, we decided to sell our non-operated acres as EXCO continues to focus on its core operating areas. We anticipate the transactions closing in the first half of this year and we plan to use the proceeds to reduce our revolver.

Slide 7 has our year-end reserve information. As you can see on the proved reserves waterfall chart we added 400 billion cubic feet equivalent through acquisitions including some 260 Bcf in the Haynesville, 116 Bcfe in Eagle Ford and 25 Bcfe for our share of the EXCO HGI partnerships Cotton Valley acquisition from BG.

We added 279 Bcfe due to an increase in gas prices which extends the economic life of certain producing properties and increases the number of economic proved undeveloped locations. We also added 86 Bcfe of discoveries in an extension through development drilling in the Haynesville, Eagle Ford and Marcellus.

These increases were partially offset by divestitures of 358 Bcfe the majority of which was our contribution of properties to the EXCO HGI partnership and production of 162 Bcfe. The reserves added particularly in the Eagle Ford are more valuable on a unit basis due to their oil content.

In addition we had a reduction of 127 Bcfe related to performance and other factors, 92 Bcfe as 127 was related to the Haynesville shale. I'm going to spend some more time discussing this in some detail.

First we believe our PDP wells are among the best performers in the play. Most of you on this call know high cumulative production is compared to production life is a very positive factor when reviewing shale reservoirs. We have wells drilled in 2009 and 2010 and have already produced average cumulative production of 5.2 Bcf and 4.4 Bcf respectively. However there have been some recent factors that have affected our PDP performance. One factor that has contributed to our reserve revision in the Haynesville

Shale is Highline pressure.

A majority of our Haynesville Shale wells produced into a high-pressure gathering system and are experiencing liquid loading. These pressures have impacted our PDP performance and as a byproduct have also impacted our proved undeveloped reserves. We're taking actions to improve the situation. We're working with our midstream provided to reduce line pressures and alleviate loading and we will have some additional data on this production impact in the near future.

We've also been adding artificial lift to enhance the existing production. Well spacing is a key consideration in our PDP performance. We began our development in the Haynesville with eight wells per section spacing based on higher natural gas strip prices and our focus on getting wells drilled to accelerate gas production.

We drilled 35 out of our 42 develop sections with this eight wells per Section spacing to our PDP well performance is heavily weighted towards this. We've since shifted to seven wells per Section and have drilled six sections with this spacing. The wells drilled under seven wells spacing have outperformed the eight well spacing.

In addition our wells offset to the unit wells have been impacted, so we'll be adjusting the spacing to distance the offsets from the cumulative production pressure sinks to the unit wells that have been on production for over three years. Most recently we drilled one section with six wells per section and put these wells online in November. We plan to drill seven sections in 2014 with six wells per section. We decided to continue development based on six wells per section as it optimizes our economics on our per well and per unit basis.

With our ability to manage drilling completion costs, we can generate higher rates of return and run better section economics versus spending additional capital on an incremental section well. While we expect all of these efforts to enhance our production from existing and new wells, these planned improvements will not be incorporated into our proved reserves until we have the data to support and objectively quantify these results.

As we look at our year-end reserves, we believe our proved reserve numbers are fairly conservative as the production we're seeing from multiple wells drilled on seven well spacing is above our third-party engineer proved undeveloped type curve. We believe our Haynesville and EURs will approach seven BCF per well on six well per section spacing, but we must evaluate our spacing and operational improvement effort results before we give you a more definitive EUR.

Now turning to Slide 8, our 2014 capital budget is $368 million, which is 8% higher than our 13 CapEx of $340 million. 80% of our budget is directed towards development activities totaling $294 million and East Texas North Louisiana represents 50% of our total budget. This budget was developed before we witnessed the recent increases in near-term natural gas prices. We continue to monitor the movement near and long-term natural gas prices as we evaluate our future activity levels. While we remain committed to managing our capital spending, we could add additional rigs if, if, if the economics exceed our return hurdles.

On Slide 9, you can see EXCO's 70,000 net shale acreage across East Texas and North Louisiana. Our core Holly position includes about 30,000 net acres in DeSoto parish, where we had 369 wells flowing to sales on 42 developed units at year end.

For 2014, we plan on developing seven of our 37 undeveloped units by drilling 34 wells in the Holly area. We’ll also be drilling the Shelby area of East Texas in 2014. We have about 70,000 net acres in Shelby with 70 flowing to sales at year end. Our historical Shelby activities have been focused on delineation drilling, technical evaluations, and completion and flowback design testing.

Based on our ability to apply the skills and learnings we developed in the Haynesville with managing drilling completion costs and the recent success of other operators on offset acreage near Shelby, we're resuming this drilling program. We plan on drilling eight wells with laterals up to 7,000 feet increased profit per completed foot and more restricted flowback. If this drilling completion proves successful, this program will provide a growth platform for future development.

Slide 10, provides additional detail on the success we've had with optimizing drilling efficiency and realizing significant savings. The chart on the left highlights our spud to rig release performance as we improved from 56 days in 2009 to 33 days in 2013, representing a 40% reduction. And very importantly, it demonstrates our improved performance every year. The chart on the right compares EXCO's spud to total days to other operators and indicates our consistent outperformance as compared to our peers with the dashed green line sloping down and to the right over time.

For 2014, while we're modifying the Holly frac design by adding three frac stages with water well spacing. We still expect our drilling completion costs to total only $7.5 million per well. Our Eagle Ford operations are outlined on Slide 11. We have about 48,000 net acres in the oil window with an option to earn additional net acreage. Our acreage is primarily held by production and also includes additional upside and other formations including Austin Chalk, Buddha, and Pearsall.

We drilled 23 wells in the core area of Zavala County from the end of July acquisition date to year end 2013 and turned seven to sales with average initial production rates of 570 barrels of oil a day. At year-end, our shale oil production from 140 wells averaged 6,700 net barrels of oil per day. In 2014, we plan on drilling 90 gross wells on 500-foot spacing with a five rig program. We're continuing to evaluate our farm-in option acreage and plan to drill 6 farm-in wells during 2014.

We’ve utilized our expertise developed in other shale areas and have realized significant operational efficiencies. We're averaging 15 days from spud to rig release and our drilling completion costs are averaging $6.9 million per well, approximately 8% lower than in July. Our operations team is working on gathering systems, compression and central facilities to reduce total project costs and improved returns.

We expect to install 90 pumping units in 2014 to enhance existing production. We're currently evaluating 37,000 net acres that are perspective for the Buddha formation. We've licensed about 500 square miles of 3D seismic data since this evaluation we're monitoring operator activity on offset acreage and we expect to complete our announcement later this year and we'll provide you an update when done.

The map on Slide 12 highlights the broad acreage position we have in Appalachia. EXCO holds some 290,000 net acres with approximately 145,000 net acres perspective for the Marcellus shale. As you look across our three focus areas Appalachia has largest undefined shale resource potential based on this large acreage position. We’ve focused our shale efforts in Armstrong and Lycoming County Pennsylvania. At year-end we operated 124 Marcellus wells and total net Appalachia production including both shale and conventional well averaged 65 million cubic feet equivalent per day.

Our Appalachia production has been relatively stable for the year averaging 63 million cubic equivalent per day, which we think is impressive given the low level of capital we've deployed in the area. We've had strong results on some recent wells turned sales and one well IP to $11.3 million cubic feet a day in December. With our 70% held by production position in the region we control the timing of the development of our acreage but due to regional price differentials we've reduced our drilling program in this region we plan on only drilling two appraisal wells during 2014.

With that 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 just want to make one comment before I dive into the numbers here. A lot of the notes this morning and some of the issues around our release that focused on some of the matters that Hal talked about Spacing, Highline pressure, those types of things. I just want to emphasize one point that Hal made in his presentation at the end of 2013, this company operates 7,863 wells that’s a lot of experience we have a very strong technical team.

We are dug into these issues on Spacing, Highline pressure, and have every confidence in the world that we will address them and fixed those issues. So look for that as we go forward with respect to those technical challenges. So on the table on Slide 13 has the financial highlights for the quarter and the full year. And you can see that we had improvement on revenues, adjusted EBITDA, and adjusted cash flow driven by the increase in oil production. Hal previously noted our positive performance as compared to our – the midpoint of our guidance so all in all a solid finish in the quarter to a productive 2013 for EXCO.

Slide 14, demonstrates our positive deleveraging momentum. Since net debt peaked at almost $2 billion at the end of the third quarter, we have worked aggressively to get our leverage metrics and debt back to the appropriate levels. With the closing of the West Texas asset sale, we will have reduced net debt by $582 million since September 2013. And we expect our 2014 CapEx to be well below our adjusted EBITDA.

The reduction in outstandings on our revolver balance has enhanced our liquidity as shown on Slide 15. Adjusting our year-end numbers for the pending West Texas transaction, we expect to have $534 million in liquidity and we believe dispositions us well going into the quarterly buybacks beginning in 2015. With respect to our partnership in the Eagle Ford, in the second half of 2013, we drilled 23 wells that we anticipate will be eligible for buyback from our partner in the first quarter of 2015.

We have analyzed what that potential buyback might look like using current strip pricing to estimate the amounts. Using round numbers we estimate our partners’ capital investment for those 23 wells is approximately $90 million. To achieve their drilling capital return they need to receive approximately $108 million. We estimate approximately $58 million of that $108 million will come from first-year cash flow leading $50 million is the buyback that EXCO would need to fund.

We estimate the PV10 value for the interest we’re making and offer on at that time to be approximately $86 million. We believe that the PV10 value is more than sufficient to allow us to finance the buyback with conventional reserve based lending.

So as outlined in this example, EXCO would have no financing shortfall and the buyback would be 100% funding by first year cash flow and revolver capacity from the producing developed reserve value we acquire. I almost feel like I should read that again. Because there has been a lot of speculation about the financing pressure around this relationship. So I'm going to read it again.

With respect to our partnership in the Eagle Ford in the second half of 2013, we drilled 23 wells that we anticipate will be eligible for buyback from our partner in the first quarter of 2015. We’ve analyzed what that potential buyback might look like using current strip pricing to estimate the amounts.

Again using round numbers we estimate our partners’ capital investments for those 23 wells is $90 million. To achieve their drilling capital return they need to receive approximately $108 million. We estimate $58 million of that $108 million will come from year one cash flows leaving $50 million as the buyback amount EXCO would need to fund.

We estimate the PV10 value for the interest we are making and offer on at that time to be approximately $86 million. We believe the PV10 value is more than sufficient to allow us to finance the buyback with conventional reserve based lending.

And again as outlined in the example, EXCO would have no financing shortfall and the buyback would be a 100% funded like first year cash flows and revolver capacity from the PDP reserve value acquired. So again there has been some commentary about our financing pressures assuming the scared revolver based lending market remains intact our analysis and projections indicated the funding needs to satisfy the buyout requirements are well within our financing capabilities in 2015 and beyond.

So Slide 16 has our first quarter 2014 guidance and we’re confirming the previously announced full-year 2014 EBITDA guidance of $400 million to $425 million. EXCO projects first quarter adjusted EBITDA to be $105 million to $110 million with a production midpoint of 405 MMcfe per day. The adjusted EBITDA range for the first quarter is based on NYMEX pricing of $5 for natural gas and $98 for oil.

The fourth quarter 2013 to first quarter 2014 production decline of 9% is primarily attributable to timing of completion activities in East Texas, North Louisiana and shut-ins due to offset completion activities in South Texas.

EXCO currently has five rigs running in East Texas, North Louisiana which will fully develop seven units during 2014. The majority of our expected wells be turn to sales for 2014 occur in Q2 and Q3 with the first fully developed Haynesville unit schedule turn to sales early in the second quarter.

The South Texas EXCO currently has five operated rigs running focused on our core area acreage. We are currently experiencing a high level of shut-ins due to offset completion activities in the core area. You should note that the South Texas wells currently being developed have a lower working interest of approximately 16% in their first year production before the buyback versus EXCO’s existing PDP wells of approximately 66% working interest. We give you that color, just so you can interpret the guidance and see the scaling through the year.

For the full year our adjusted EBITDA range is based on first quarter prices previously discussed and then $4 natural gas and $90 oil for the second to the fourth quarters of 2014. 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 price. Currently for 2014 – for 2014’s expected production approximately 83% of our gas and 94% of our oil are subject to hedges at average swap prices of $4.23 and $95.70, that’s in the appendix of the slide deck we provided.

So before we conclude I want to touch on just a couple other items. Our Board meeting is scheduled later in March than last year. So any decision on a first quarter dividend will be made at the meeting on March the 10th. As always, any future declaration of dividends, as well as establishment of record and payment dates is subject to the approval of the Board. In addition based on discussion with investors, we have decided to not schedule on Analyst Day in Dallas until after we have a new CEO in place.

So in conclusion, we have demonstrated that we are executing on our strategy and delivering on our commitment. We have a clear predictable growth pipeline and look forward to both production growth and adjusted EBITDA growth in the years to come. Our balance sheet improvement and liquidity are more than adequate to fund the buyback and we believe successful execution will result in increased value for our shareholders.

So thank you for your time this morning. Now Hal and I will take your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of Leo Mariani. Your line is open.

Harold L. Hickey

Good morning, Leo.

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

Hey, guys. Could you share any data on kind of any recent Eagle Ford well results, maybe just in terms of I don’t know IPs or 30-day rates or EURs and what you've seen out there in the field now that you guys are out there operating?

Harold L. Hickey

What we said in our presentation, we’ve averaged about 570 barrels of oil per day on the wells that we’ve drilled of late. So we’re realizing the results that we anticipated and it’s steady as she goes.

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

Okay. And I guess in terms of the buyback example, Mark, that you quoted in 2015, I guess just to be clear, so you're basically saying your current estimates are roughly $50 million a quarter based on example in 2014?

Mark F. Mulhern

That’s right.

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

Okay. And then I guess additionally, you mentioned that that could be entirely financed under the revolver. Would that be the actual plan is to finance that entirely under the revolver or might you also think about alternative ways to fund it going forward?

Mark F. Mulhern

Yes, we – what I would say is, I don’t think we’re making any commitments exactly now about how exactly we’ll finance it. But I think my point of the example was to demonstrate that we believe the PV10 value of the properties we acquire will give us additional capacity. And we believe that that’s readily doable in the bank markets the way they currently operate, so that’s kind of how I would think about that. And you’re right, it would be roughly $50 million a quarter again we think we can finance a number of ways, but the revolver option would clearly be available to us.

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

Okay. And I guess the smaller asset sale you've made in the Permian, I guess it's good to see improved liquidity. Is there any production associated with that or is that just acreage?

Harold L. Hickey

There is a couple of wells that are online now. The wells were making somewhere between 300 barrels and 400 barrels of oil a day on average.

Mark F. Mulhern

Leo, we didn’t have anything in the borrowing base. So there is nothing in the secured borrowing base related to this asset, where we were just developing it at the end of 2013.

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

Okay. That's helpful color. Thanks, guys.

Harold L. Hickey

Hey, Leo, one more thing before you leave…

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

Yes.

Harold L. Hickey

I want to go back to the Eagle Ford just for a minute. The question you asked about EURs and production, here’s what I would say, the good news on the Eagle Ford from my perspective is, so we’re interested in production, we’re interested in cost, we’re obviously interested in the price of a commodity, so here is what has happened since we made that acquisition in July of last year. Our guys have done a fabulous job on the cost side.

So I can’t remember, we – I think we had 7.2 million of well in our original estimate. I think we’re trending below 7 million and making further progress there on the cost side. On the production side, we’re generally in line with where we expected things to come, but we are doing a lot of artifical list, so I think we’ve got planned like 90 artificial list for 2014, so we expect that to help the production levels and so I think we are satisfied in that arena and oil prices right now we would have projected back in July that those would be lower than they are today.

So in our minds, we are making good progress on that acquisition and have had good success in integrating it and getting things to where we want them to be. Obviously, our goal is to replicate the manufacturing capability, we’ve proven in Haynesville and we believe we're on our way to doing that.

Mark F. Mulhern

One more comment on that as far as the IP goes I was quoting 24-hour IP, I think the 30-day IP is around 450 barrels today of oil. And one other comment I will make is that we are seeing some leasing opportunities down in Eagle Ford, so we picked up some additional acreage of late.

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

All right, thanks, guys, really helpful color.

Operator

Our next question comes from the line of Will Green. Your line is open.

Will Green – Stephens Inc.

Hi, guys.

Mark F. Mulhern

Good morning.

Will Green – Stephens Inc.

I appreciate all the color around the Eagle Ford. Can you help us with how that $450 million barrel 30-day housing hydrocarbon split looks on that? What kind of pricing you're getting on your crude if, I assume it's fairly standard gravity, but any color around that would be great.

Harold L. Hickey

The 450 barrels day that we quoted is our oil number. And we didn’t make some minimal amount of gas down there, but it’s not significant in our valuation.

Will Green – Stephens Inc.

Gotcha. And then how are you guys thinking about first year declines at this point out at that Eagle Ford asset? I know it's fairly early, but how are those wells tracking on a first-year decline?

Marcia Reeves Simpson

We are looking at this point we really don’t have any new production that you know to go operations here, but basically estimated about 73% decline in the first-year 38% in the next year first flat now.

Will Green – Stephens Inc.

Thanks. And maybe hopping over to the Haynesville, you guys have re-initiated over in Shelby. Haynesville's been a great place for you guys to get operating costs and well costs down. How should we think about those Shelby costs starting out and where you expect to get to as that gets started back up?

Mark F. Mulhern

Well, as you know its deeper higher pressure, higher temperature, early on in the play we were exceeding $12 million for drilling and completion costs at Shelby. We are anticipating that we will be drilling these wells and completing these wells for about $3.5 million at this point.

Will Green – Stephens Inc.

Great.

Mark F. Mulhern

And we are of course drilling much longer lateral over there than compared to Holly. We are talking about 7,000 foot laterals.

Will Green – Stephens Inc.

Sure.

Unidentified Company Representative

In more frac stages et cetera.

Will Green – Stephens Inc.

Right. I appreciate all that guys.

Unidentified Company Representative

Thank you.

Operator

Our next question comes from the line of Amir Arif. Your line is open.

Amir Arif – Stifel Nicolaus

Guys just a few questions first on the Eagle Ford when you are looking to buy those Eagle Ford assets on a quarterly basis, what commodity prices you used to determine the payout to KKR?

Unidentified Company Representative

Yes we use, so the estimates that I read you the estimates that I read you we were using 2014 prices whatever the strip was, we did announced which I think I’m reading just to give me one second 417 for gas, just over $90 for oil for the 2014 prices and then we were using again a current strip that added up 80 on the tail kind of 420-ish on the tail-end gas.

Amir Arif – Stifel Nicolaus

But to determine the right number, what is the time is that the strip price or?

Unidentified Company Representative

Yes. It is the strip price at that current time. So in 2015, we will use the current strip to do that valuation. That has integrated.

Amir Arif – Stifel Nicolaus

Okay and then for you I mean the bank commodity steel infrastructure is sometimes lower but I guess they would give you benefit of any hedges that you have against that production?

Unidentified Company Representative

They do give us benefit of the hedges and they generally use your rate of discounted number of that but PV9.

Amir Arif – Stifel Nicolaus

Okay. And then on the I mean if you kept your 2014 E&D spending flat into 2015 and if we just lever in this acquisitions is that enough to turn top line corporate production around?

Unidentified Company Representative

I’m just I hesitate to give you that number only because we haven’t done the full analysis, no we obviously have declines in Haynesville and declines from the other areas but we are going to pick up production as result of these buybacks. I would say we would give you guidance for 2015 when it’s time.

Amir Arif – Stifel Nicolaus

Okay. And then maybe you bond these assets after about a years of initial decline, I mean after you’re holding for a couple of more years is the decline low enough or make sense for you guys to drop it into your MLP or is that a thought process that churn out interest again?

Unidentified Company Representative

That is something we have thought about and considered and would considered at the time is the way I would characterize it.

Amir Arif – Stifel Nicolaus

Okay. And then just a final question on the Haynesville side, I apologize that is drop off on the call but the drainage issues that only in Holly or you also seeing that in the Shelby area?

Unidentified Company Representative

Really are seeing it in Holly. We don’t have enough development in the Shelby area to really draw conclusion what is happening there. But what we’re seeing is where there is production that the current over time, the immediate offset wells to the unit wells are seeing lower EURs if you will because of drainage.

Amir Arif – Stifel Nicolaus

Okay it is showing up on the IP as well or is it just under EUR in terms of the curve just declines faster?

Harold L. Hickey

I think it’s showing up more in the curve not as much in the IP, because we're on a restricted flowback program and we can manage those returns. We're still getting similar IPs on those wells as we are and others.

Amir Arif – Stifel Nicolaus

Okay. And if you switch to the six per section instead of eight, I mean obviously EURs might come down, but on an MPV basis, any color on how much of an impact?

Harold L. Hickey

First, let me say EURs per well on a six well per section basis we will go up.

Amir Arif – Stifel Nicolaus

Let’s go up, yes.

Harold L. Hickey

Yes. So follow-up with your next question, I’m sorry.

Amir Arif – Stifel Nicolaus

So, on an MPV basis per section, any idea how much of that would change?

Harold L. Hickey

We are going to increase PV10 per section by going through the six wells and going through the anticipated EUR that we think will increase as we continue with our operational improvement. I hesitate to give you that exact number.

Amir Arif – Stifel Nicolaus

Okay, fair enough. Thank you.

Operator

Our next question comes from the line of David Heikkinen. Your line is open.

Harold L. Hickey

Hey, David.

David Martin Heikkinen – Heikkinen Energy Advisors, LLC

Good morning and thanks for the explanation on how you financed the buyback by borrowing against PDP. I understand the partner guaranteed returns. Have you calculated or can you share what your calculated return to EXCO equity is using the math you just walked through?

Mark F. Mulhern

I haven’t calculated it and I don’t have it right in front of me. But if you look back on our Investor Relations website, we had it in a presentation. We had it in a couple of presentations that we filed what we gave you our comparable return on capital to KKR’s, but I don’t – I just don’t have that right in front of me.

David Martin Heikkinen – Heikkinen Energy Advisors, LLC

Okay. And then I guess just on the other side, just thinking about the return hurdle for more gas drilling given the way the strip is, and then thinking about that versus the capitalization and the clear ability to finance buybacks, how high would your capital budget go I guess if you did more gas drilling or do you shift capital or how does that factor in as you're thinking about more capital?

Harold L. Hickey

David, we're committed to managing our capital spending, so that we don’t exceed the EBITDA…

David Martin Heikkinen – Heikkinen Energy Advisors, LLC

Okay.

Harold L. Hickey

So use that as sort of a line in the [Indiscernible].

David Martin Heikkinen – Heikkinen Energy Advisors, LLC

Okay. That's helpful. That was all I had. Thanks, gentlemen.

Harold L. Hickey

Great. Thank you, David.

Mark F. Mulhern

Thank you, David.

Operator

Our next question – I’m sorry, our next question comes from the line of Matt [Indiscernible]. Your line is open.

Unidentified Analyst

Good morning, guys.

Mark F. Mulhern

Hey, Matt.

Unidentified Analyst

Hi. Just a quick question, I wanted to make sure I understood kind of how you guys are thinking about the Haynesville EURs. Could you give us a little context as to how you guys booked your seven and eight well section EURs and then as you mentioned, the potential uplift or improvement to the six well per section EUR that you may see or expect?

Marcia Reeves Simpson

Historically, if you go back to our 10-K, you'll see that like in 2010 we had about 6.1 BCF on eight wells per section and in 2011, we were up to 6.6 BCF. Well, we went into 2012, we were thinking we'd be more into the 7 and when we dropped down to 6, we’d get the 7 BCF at least. As we talked earlier we're getting more of 3 BCF from the auditor at this point, which we believe is going to be on low side. We see that our wells outside of the offsets are making about 6.5 BCF. So we think, it’s down – it’s going down to 6 wells will get us in about that 6.5 BCF. So we’ve never been really outside of any large ranges there.

Unidentified Analyst

Okay, great. And then just in terms of the Haynesville asset, could you give us any color on how you guys are thinking about the base decline in 2014? I assume that will start to slow a bit, but just wanted to get some context there.

Marcia Reeves Simpson

I think we’ll follow up with that on the base decline. Again, the number of wells we are bringing on has changed this year, we’re seeing a fluctuation in general, we’re seeing after the first and second year you get into about 37% to 30%, so you're 30% decline about the third year, we don’t really see that – don’t see that type of profile.

Harold L. Hickey

We also think that with some of our operational efforts that are ongoing as we speak, lowering line pressure, putting in artificial lift, using bolmor, working on our scaling that’s occurring in a very few wells. We do believe that we’ll be able to arrest of the declines and so until we get some of those results back we're hesitant to talk about what the actual numbers going to be, but I think it’s going to get better, that’s what I say qualitatively, so.

Unidentified Analyst

Great. And then last question just on the Marcellus, you guys have obviously reduced capital expenditure there given the issues around the differentials. I was wondering how you guys think about that asset strategically within the portfolio. Is that something that could potentially be used to fund growth in your higher rate of return plays like the Eagle Ford? Just wanted to get a little bit more context there.

Harold L. Hickey

There is a lot of things. As any responsible management group would do, you’re going to look at all your alternatives there. We think there is still some dramatic upside, we are very disappointed with the differentials that we’re seeing particularly in Lycoming County on gas, but we think we’ve got some good acreage positions, we’ve got some quality acreage positions that's going to afford some opportunities in the future and how that plays out we’ll just see.

Unidentified Analyst

Thank you very much.

Operator

Our next question comes from the line of Steven Karpel. Your line is open.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

Good morning guys.

Harold L. Hickey

Good morning.

Mark F. Mulhern

Good morning.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

I know we've gone over this a few times. Appreciate reading it twice, but maybe walk through it a third time here or fourth time on the wells to understand exactly the way we should think about this. I think you’re saying that it’s 23 wells and that 23 wells is going to hold per quarter? I think the math worked out to be 23 times $2 million a piece. So is that right and that assuming no ramp up as we move through 2015 and maybe even talk about all the way through 2016?

Mark F. Mulhern

I didn’t quite follow your $2 million, but let me just go through this. So we are estimating about 20 wells a quarter, 80 wells a year. So that's what we've kind of agreed to with our partner. So that would put you at 240 to 300 wells over three, four year period. So what happens is we agree, our partners and us agree on what wells we’re going to drill and where that’s all agreed-upon and we go out and execute the drilling program and those wells are then on production per year.

And there is certain qualifications they estimate for them to go into a buyout package, but what I walk you through was we drilled 23 wells, again we close the acquisition in July, August so we took the full. So the second half of 2013 in our minds are first full quarter, so a quarterly package. So those 23 wells would be in a quarterly package, we sit down and we do a PV10 calculation of those 23 wells at that time.

So in 2015, we’ll do the math using the current strip we will go and then make an offer to our partner to buyback those wells and we’re allowed to credit effectively against the purchase price, the amount of first year cash flow that they received. So and the example that I read to you the 23 wells, our partner put up $90 million of capital on those 23 wells for them to be required to sell to us, we got to get them a $108 million of return on that $90 million and $58 million of that is coming from first year cash flow.

So that leaves you $50 million to get to them as return which we believe we’ll do through again an example I used, we may do it differently, but an example I used we believe that we’ll have $86 million of PV10 value for those 23 wells, which we think in today’s bank market we could finance that some advance rate which give us plenty of capacity to come up with $50 million to the revolving bank loan market and therefore EXCO wouldn’t have a shortfall at that point in time, we wouldn’t have to put in any of our free cash flow, we would finance to buyout between the first year cash flow and whatever revolving capacity we acquire.

And believe that’s going to be replicable every quarter, so we're going to keep doing that every quarter for the next 12 to 16 quarters depending on how we get through this drilling program and that's the arrangement that we have in place.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

Right.

Harold L. Hickey

So the $2 million was the $50 million to finance divided by the 23 wells.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

Got it. Got it.

Unidentified Company Representative

So we should just think about it financing somewhere in the neighborhood of maybe wells a year at $2 million is $160 million.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

That’s very fair.

Unidentified Company Representative

And then the second part of that is as a result of that financing that you‘ve done, I know paid on the revolver and what not, when do you think about terming that out, the rest of that as you are going to ramp back up nine months from now with a little bit of use there. So when you think about terming out the revolver I guess.

Harold L. Hickey

Yeah, so here is Hal I think about it just from a balance sheet and fiscal responsible perspective I would agree with your commentary we are a little highly drawn on the revolver all those got much better, since we’ve got to slides offering and the sale of TGGT and now the sale of this West Texas property, we are in very good stead with revolver in terms of where we are in terms of drawn, but I agree with you we look at it all the time. I'm not telling you when we're going to do this but we look at terming out. We look at our options around how we should finance and what's the prudent thing to do? So we'll continue to do that as we go forward.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

What do you think about as potential options that coming back to the bond market like you have in the past?

Unidentified Company Representative

I think that will on the table, sure.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

And then just last one, obviously the big hire in the conventional JV/MLP. What's your game plan there in terms of growing that and how do you grow that and or what not?

Unidentified Company Representative

Yeah, I mean so here is what I'd say about that Harbinger and EXCO entered into this partnership to develop these conventional assets, we put some of the EXCO assets into that partnership and had been trying to look for opportunities to grow that platform, I think that was a collective agreement that it would be helpful to have more dedicated experienced leadership and that’s how Matt Grubb came to the table, Matt got hired, he is an ex-SandRidge guy got a lot of experience, so we’re excited have and we think it’s going to be very good for our growth plans, for that partnership and we are very much aligned with Harbinger around trying to grow that MLP and try to create some value there.

Unidentified Company Representative

There is a significant effort is ongoing on the business development front to dry to identify growth opportunities [indiscernible] getting the door.

Steven M. Karpel – Credit Suisse Securities (USA) LLC

Thank you guys.

Unidentified Company Representative

Thank you.

Operator

(Operator Instructions) Our next question comes from the line of Jeff Robertson. Your line is open.

Jeffrey Robertson – Barclays Capital

Thanks Mark. I was just wondering if you could share any kind of range on production for that first group of wells that you made – that you will make the offer on the first quarter 2015. From what it might be producing at that time?

Mark F. Mulhern

Jeff I don’t have that right in front of me, but if you call me I can probably get you that, I’ve got – I got a sheet numbers in front of me, I don’t have production unfortunately on this page.

Jeffrey Robertson – Barclays Capital

Okay.

Unidentified Company Representative

Just give me a call.

Jeffrey Robertson – Barclays Capital

Second question were the wells that you will drill in the program over the next several quarters be much different than the first 2013 there in the program?

Unidentified Company Representative

No we think they are going to be very similar.

Jeffrey Robertson – Barclays Capital

Okay thanks.

Unidentified Company Representative

Our partner and we have agreed on the specific wells that we will drill and identified those quarters go ahead and we are definitely in the same general areas that we believe that the results would be similar.

Jeffrey Robertson – Barclays Capital

Okay thank you.

Operator

There are no further question in queue at this time. I turn the call back over to the presenters.

Harold L. Hickey

Thank you everyone for participating this morning. We look forward to visiting with you one on one in some point in the future anyone that has any interest in further following up on this call for further questions please get in touch with us. Again thank you for your attention and your participation this morning, meeting adjourned.

Operator

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

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