Atlas Resource Partners' (ARP) CEO Ed Cohen on Q1 2014 Results - Earnings Call Transcript

May. 8.14 | About: Atlas Resource (ARP)

Atlas Resource Partners, L.P. (NYSE:ARP)

Q1 2014 Earnings Conference Call

May 8, 2014 9:00 ET

Executives

Brian Begley - VP, Investor Relations

Ed Cohen - Chairman, CEO, the General Partner

Matt Jones - President

Sean McGrath - CFO, the General partner

Analysts

Ben Wyatt - Stephens

Praneeth Satish - Wells Fargo

Michael Gaiden - Robert Baird

Majid Khan - Tourbillon Capital

Craig Shere - Tuohy Brothers

Sean Sneeden - Oppenheimer

Noel Parks - Ladenburg Thalmann

Operator

Good day, ladies and gentleman, thank you for standing by. And welcome to the Atlas Resource Partners, Atlas Energy Q1 2014 Earnings Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference call is being recorded.

I would like to turn the conference to our host Mr. Brian Begley, Vice President of Investor Relations. Sir, you may begin.

Brian Begley

Good morning, everyone, and thank you for joining us for today's call to discuss our first quarter results. As we begin, I'd like to remind, everyone, that during this call we'll make certain forward-looking statements, and in this context forward-looking statements often address our expected future business and financial performance, and financial condition and often contains word such as expects, anticipates and similar words or phrases.

Forward-looking statements by their nature address matters that are uncertain and are subject to certain risks and uncertainties, which can cause actual results to differ materially from those projected in the forward-looking statements. We discuss these risks in our Quarterly Report on Form 10-Q and our Annual Report also on Form 10-K particularly in Item 1. I'd also like to caution you not to place undue reliance on these forward-looking statements, which reflect management's analysis only as of the date hereof. The company undertakes no obligations to publicly update our forward-looking statements or to publicly release the results of any revision to forward-looking statements that may be made to reflect events or circumstances after the date hereof or reflect the occurrence of our anticipated events.

Last week, as you may know, yesterday we filed a perspective supplement with the SEC in connection with an offering of our common units. We have been advised by counsel that we cannot discuss that offering or any details related to our recently announced agreement to acquire certain assets in Colorado other than the information regarding the acquisition that was included in our announcement yesterday.

With that, I'll turn the call over to our Chief Executive Officer, Ed Cohen, for his remarks. Ed?

Ed Cohen

Thanks Brian, and welcome everyone to our first quarter 2014 ARP, ATLS conference call. We got a lot to cover today. We will be reporting both on first quarter results for Atlas Resources Partners, ARP and for Atlas Energy Inc. rather LLC ATLS and we will also be discussing ARP's agreement will require approximately 47 billion barrels of oil equivalent and that's of mature Low Decline oil and natural gas liquid reserves in Northwest Colorado and we are paying $420 million.

First ARP's purchase in Colorado, the asset position located in the Rangely field in Northwest Colorado is a tertiary oil recovery project using CO2 flood activity. The 47 million barrels oil equivalent being purchased or an approximate 25% net working interest in the entire play.

During the first quarter of 2014, the resources to be acquired by ARP averaged net daily production of approximately 2900 barrels of oil equivalent per day of which about 90% was oil and the remainder natural gas liquids NGLs. These hydrocarbons are expected to provide ARP with stable high margin cash flow with a markedly low decline in production. To put that in context over the past 15 years, the average annual decline rate is averaged between 3% and 4%.

Once again, we will be working with Chevron Corporation which will continue as operator. Material capital expenditures in growth projects, however, are subject to ARP's approval. In my opinion these are ideal assets for an E&P MLP long lived, low decline, but with potentially valuable development opportunities upside expansion potential from over 20 million barrels of oil equivalent of undeveloped reserves. But easing at the present time, the transaction is expected to be immediately accretive on a fully financed basis the distributable cash flow per unit.

Now, let me address ARP's first quarter results. First quarter 2014 adjusted EBITDA was $64.5 million compared to $62.6 million for the fourth quarter 2013 and only $31.4 million for the prior year comparable quarter. Results during the quarter, however, were adversely impacted by severe winter weather conditions. In some cases unprecedentedly adverse. These conditions constrained production volumes costing ARP approximately $3.5 million in the quarter. Distributable cash flow for the quarter in any case came to $42.3 million or $0.53 per common unit compared to $41 million for the fourth quarter 2013 and $25.1 million for the prior year comparable quarter.

Eliminating the weather impact, ARP's first quarter 2014 cash distribution coverage would have been approximately 1.0x. Including the monthly payment to be made on May 15th, ARP will pay cash distributions totaling $0.58 per limited partner unit for the first quarter 2014 an approximate 14% increase over the prior year first quarter distribution.

On the physical front, averaged net-net daily production for the first quarter 2014 was 246.6 million cubic feet equivalent per day an increase of approximately 85% from the prior year comparable quarter, but a decrease of approximately 5% from the fourth quarter 2013. This decrease in quarter-to-quarter production was of course due to the impact from extremely adverse winter weather.

I'm glad to report; however, at ARP's development activities in the liquids rich Mississippi Lime and Marble Falls plays continue to yield significant levels of oil and liquids production. And by the way, I'm also glad to report that ARP's previously announced acquisition of GeoMet Natural Gas properties in West Virginia was recently approved by GeoMet shareholders.

Few words about Atlas Pipeline Partners, APL, another major constituent of Atlas Energy. Despite the enormous increase in processing capacity that APL has achieved almost a doubling in the past two years, APL's 14 plants operated throughout the quarter at 92% of capacity. APL today is processing natural gas at almost 100% of its capacity and that capacity is now reached approximately 1.5 billion cubic feet per day. With one exception, which is operating at approximately 70% level, APL's 14 plants are processing at or above main play capacity forcing Atlas pipeline to offload or bypass 80 million cubic feet a day. It hasn't been that long ago that the company's entire energy utilization was about that amount.

Fortunately three new plants are nearing completion to help us deal with this embarrassment of [plant] (ph) and APL has just announced the scheduled construction of a fourth plant in the northern part of the Permian play in West Texas. All this activity underlay the fine financial results that APL announced in its conference call on Tuesday. Matt Jones, ARP's President will now speak on operations after which Sean McGrath, CFO, will handle financial highlights for ATLS and APL. Matt?

Matt Jones

Thanks Ed.

And what an exciting time for Atlas Resources Partners. The acquisition of the Rangely field assets brings to our company the significant interest in a proven world-class oil field. A long live low decline and high margin oil production will serve to further reduce our portfolio decline rate, further diversify our production mix and add to the stability of our cash flow stream for many years to come.

The asset is operated by Chevron and no surprise, Chevron has a long history of successfully operating and managing this and other CO2 waterflood project. This acquisition follows and complements our acquisitions in the recent past of long-lived and low decline natural gas assets, it also have provided significant stability to our cash flow stream.

As of today at ARP, our operations in producing assets extend across 14 states, including the Raton Basin in northern New Mexico and now with the acquisition announced yesterday in the Northwestern Colorado and the world-class Rangely field, and to Oklahoma in Texas where we benefit from core positions in the Mississippi Lime play, the Barnett Shale and the oily Marble Falls development area. In the Eastern Oklahoma and through the Black Warrior Basin in Alabama and under core areas of the Marcellus Shale play in the Southwestern, Northeastern Pennsylvania.

The breadth and diversity of our assets provides a substantial core of long live low decline natural gas and oil production and a sizeable inventory of potential high returning drilling locations creating meaningful organic growth opportunities. Our focused effort at ARP is to increase the stability and growth of our cash flow per unit. We do so by emphasizing our core strengths of acquiring and simulating long-lived oil and gas properties and by exploring potentially higher returning drilling prospects.

Our acquisitions have substantially increased our producing asset base and materially lowered our portfolio decline rate. Expanding the scope of our operations provides the obvious benefits of diversification and also creates operating platforms for future growth. Lowering our decline rate as the advantage of creating greater stability and reducing the amount of maintenance capital required relative to total production in cash margin.

We've grown organically and through the exploitation of our liquids rich drilling opportunities in high yielding dry gas locations. We funded the vast majority of our drilling activities by raising drilling capital through our tax advantage direct investment program business. Raising drilling capital in this form serves to reduce the capital intensity of our organic growth, enhanced is our rates of return and increases monthly recurring cash fees that we generate further adding to this stability of our cash flows.

Our drilling program remains diverse and highly concentrated in oil and liquids rich areas. We believe that focusing on the exploitation of liquids enhanced drilling locations, allows us to efficiently replace natural declines in our producing assets and provides attractive drilling prospects for our company and for those who invest in our direct investment drilling programs.

The execution of our strategy and effective management of our drilling asset base has led to, what we believe to be a peer leading distribution growth rate over the last couple of years. A key contributing to our cash flow growth has been more than a six-fold increase in production over that period of time.

In the first quarter of 2014, our company's cash distribution per unit increased by 14% and our production by 80% compared to the first quarter of 2013. Much has been said about the severe weather conditions that prevailed in the first quarter and we are not immune to the challenges created and we're certainly negatively impacted. However, I'm pleased to report that our operating teams performed admirably, minimizing the impact to our business and continue to advance the development of our organic growth projects.

The best evidence of this is the ramp that we have experienced in our oil production since the end of the first quarter. For the first five weeks of the second quarter, the current quarter, we've increased our average net oil production to roughly 1,800 net barrels per day compared to the 1,560 or so net barrels produced in the first quarter, an increase of 15%.

Some of the increase relates to production returning from shut down wells and some from wells that were delayed because of weather. Perhaps the best news is that we continue to see our oil production ramp and we anticipate further growth. Measured against our company's net oil production in the first quarter of 2013, our average daily oil production so far in the second quarter represents a growth rate exceeding 60%. So what's creating the high growth in our oil production over the last year? The entirety of our liquids production growth has been generated organically through the drill bit. And nearly all of it is coming from our development of our Mississippi Lime and Marble Falls assets, with the vast majority of those wells having been included in our drilling investment programs.

We plan to continue to dedicate a substantial portion of our drilling activity to these two areas and in our 2014 Series 34 Drilling Program. In our Mississippi Lime position were scheduled to connect additional 14 wells to the remainder of the year 2014 year, will connect one of the 14 wells before the end of the second quarter, two of the wells early in the third quarter, four wells late in the third quarter, and seven of the wells intermittently throughout the fourth quarter.

The vast majority of the wells are scheduled for inclusion in our Series 33 and Series 34 Direct Investment programs. We generally have two rigs running on our acreage in the Miss Lime through the remainder of the year to accommodate the scheduled pace of drilling. Our Miss Lime wells connected in the first quarter performed well exceeding type curve expectation. This continues a trend of outperformance for our Miss Lime activity dating back to the third quarter of last year.

Also importantly, the composition of production for the first quarter advantage of wells is roughly 50% liquids and that's consistent with that performance. We reported fairly extensively on past quarterly calls about the progress that we've made with our Mississippi Lime position. Over the past year or so, well cost have trended lower and our production results have materially improved.

The credit for this of course goes to our geology staff and our asset development team for the results that we're achieving in the play. In the Marble Falls, we're scheduled to connect an additional 48 wells to the remainder of 2014. We'll connect 14 of the wells through the remainder of the second quarter and early in the third quarter, following that we'll begin connecting the remaining 34 wells in August with scheduled connections of roughly seven wells per month through the end of the year.

We planned to generally run two rigs for the remainder of the year in the play to accommodate our drilling program. A vertical drilling program of the Marble Falls allows us to complete multiple zones and see exact pay opportunity from various formations including the Marble Falls, Barnett Shale, Bend conglomerates, the Caddo and Chappel Reefs. We continue to integrate well data, 3D seismic interpretation and drilling and completion practices to minimize lower producing wells and maximize higher producing wells.

Worth noting that our Marble Falls region was the hardest hit among our areas of operations by the severe weather conditions in the first quarter. High storms and well freeze-offs delayed production from existing wells, delay completion efforts on certain wells and because of road closures prevented water and oil trucks from reaching development areas in well sites.

The recent ramp in our company's oil production relates primarily to the abatement of the negative weather conditions affecting the Marble Falls region. The performance of our operating team in overcoming the negative conditions and the addition of a number of high performing wells over the last 6 to 8 weeks.

Moving to our Utica position, we are on schedule to connect three wells in late June on our Columbiana County property where we hold roughly 1,200 contiguous acres. We drill the three wells from a single pad site and completed a fracing of 51 stages during the first quarter. All operations proceeded according to plan.

The wells are being funded through our Series 33 Direct Investment program, also because of the advantageous configuration of the property; we estimate that we have at least 7 or 8 additional drilling location with individual lateral lines exceeding 5,000 feet.

Staying in Appalachia and moving to the Marcellus Shale, we planned to drill three wells on our Lycoming County acreage in the third quarter. We'll drill wells from a single pad side on acreage that is very close proximity to our existing, outstanding wells in Lycoming County. We currently have eight wells producing from our Lycoming County acreage and after nearly 9 months of production, they continue to produce nearly 5 million cubic feet of natural gas per well per day. Little wonder that these wells were assigned average EURs of 10 Bcf or 80 Bcf collectively.

We anticipate connecting the additional three wells that will begin drilling in the third quarter through our established infrastructure and look forward to initial production early in the first quarter of next year. These wells are scheduled for inclusion in our Series 34 Drilling Investment program.

So in total our drilling activity for the remainder of the year was focused on our core liquids areas and high yielding dry gas opportunities. We're of course excited about the forthcoming development plans for our undeveloped acreage positions and we anticipate continued success in each of the regions.

Lastly, I would like to mention that the low decline long-lived assets that we acquired in July of 2013, our largest acquisition to-date continue to perform at or above expected levels based on acquisition assumptions. This of course brings my comment full circle and back to our acquisition announced yesterday.

With our company's combination of long live, low decline assets, proven ability to acquire and simulate and manage oil and gas assets at an attractive and diverse inventory drilling locations that we anticipate funding through our advantage direct investment program business. We remain very excited about our future and look forward to updating on future calls.

On to Sean McGrath, CFO.

Sean McGrath

Thank you, Matt, and thanks all of you for joining us on the call this morning.

Regarding our first quarter financial results for ARP, we generated adjusted EBITDA of approximately $64.5 million and distributable cash flow of approximately $42.3 million or $0.53 per unit. These amounts are pro forma for a full quarter of gross margin and maintenance CapEx associated with our acquisition of the GeoMat assets, which we expect to close upon in May.

As Ed and Matt mentioned previously, our first quarter results were unfavorably impacted by approximately $3.5 million or $0.05 per LP unit due to lower volume in ARP's Barnett, Marble Falls and Mississippi Lime regions due to severe winter storms during the period. ARP distributed $0.58 per limited partner unit for the period based on these results representing an approximate 1x coverage ratio for the quarter adding back the storm impact and 1.1x on a rolling forward quarter basis.

Adding back the impact from storms, production margin for the first quarter was approximately $63 million which represented 100% increase compared with the prior year first quarter and a slight increase in the fourth quarter of 2013.

Production volumes were approximately 247 million cubic feet of equivalents per day for the first quarter compared with the fourth quarter 2013 production volume of approximately 261 million per day. This decrease was principally due to a large amount of production volumes impacted by storms and winter weather as compared with the sequential quarter as well as expected declines from the Marcellus shale loss connected during the second half of 2013 and ARP's continued focus on liquids oriented drilling.

With regard to commodity prices, natural gas prices had a dramatic uplift during the first quarter a strong demand through storage levels to record lows. Henry Hub first of month gas prices for the first quarter of $4.92 were over $1.30 higher in the first quarter compared with the fourth quarter of 2013, a 36% increase between periods. While ARP's natural gas production was approximately 80% hedged for the period, realized prices for the period of $4.07 or approximately $0.45 higher than the fourth quarter of 2013 or a 12% increase due to higher hedged and unhedged prices and improved basis differentials at a number of our sales points.

Pricing for ARP's Lycoming gas at Leidy Hub, which accounts for approximately 7% of our total natural gas production averaged almost $3.31 per Mcf for the first quarter compared with $2.85 for the fourth quarter of 2013, an improvement of over 15% from the sequential quarter although it's still reflected a 50% differential from Henry Hub, first month pricing for the quarter.

With regards to liquids, oil prices stayed strong during the first quarter as WTI prices averaged over $98 per barrel. In addition, NGL prices particularly propane were strong during the first quarter as we realized $0.76 per gallon compared with $0.73 for the sequential quarter both net of transportation and fractionation expenses.

On hedge propane prices average $1.33 per gallon for the first quarter compared with the $1.19 per gallon for the sequential quarter, a 12% increase. I think prices also saw an uplift during the first quarter of 2014, as our realized prices averaged $0.33 a gallon compared with $0.25 per gallon for the sequential quarter.

Total production costs for the period were $1.73 per Mcfe compared with a $1.49 per Mcfe for the fourth quarter of 2013. The increase from the sequential quarter was due to higher severance tax announced due to the increase in gas prices and higher leased operating expenses on a current Mcfe basis due to lower volumes mentioned previously and a slightly higher maintenance cost than our normal run rate due to timing.

With regard to our partnership management segment, margin for the quarter was $11.2 million which was $0.5 million higher than the fourth quarter of 2013 due to higher amounts of capital deployed associated with our 2013 partnership program during the first quarter.

Moving on to general and administrative expense, net cash G&A was a $11.7 million for the period, which is $3.9 million higher than the fourth quarter of 2013, due to the timing of syndication cost associated with our partnership programs. The change in cash G&A expenses was [Technical Difficulty] historically ARP's syndication of marketing cost for its partnership programs are much higher during the first quarter and significantly moderate during the latter quarterly periods.

Total capital expenditures were approximately $40 million for the first quarter including approximately $11 million associated with maintenance capital compared with $60 million for the fourth quarter of 2013. The first quarter amount included $33 million bodes direct well drilling in the Marble Falls and Mississippi Lime regions and investments in our partnership program. But the remainder associated with leased acreage and other capitalized cost.

Regarding maintenance capital expenditures as I mentioned on previous calls, we recognized maintenance capital expenditures in a manner so as to stem the decline in production margins and cash flow in future period due to natural declines in production. With regarding to risk management activities, we continue to execute our strategy methodically yet opportunistically mitigating potential downside commodity volatility for both our legacy and acquired production.

Overall, we have hedge positions covering approximately 178 billion cubic feet of natural gas production an average floor price of approximately $4.30 per Mcf for periods through 2018. And additionally, we have hedged an average of approximately 100% of our current run rate crude oil production through 2015 at an effective average floor price of over $90 per barrel with additional hedges through 2017.

As a reminder, 100% of our commodity derivatives are swaps and collars, which simply provide us with protection against commodity price movements. Please see the table's within our press release for more information about our hedges.

Moving on to ARP's liquidity position and leverage, at the end of March, we had approximately $370 million of availability under our $735 million revolving credit facility, with a leverage ratio of approximately 3.9x.

With regard to Atlas Energy LP, we generated distributable cash flow of almost $22 million and distributed $0.46 per unit for the period, representing a coverage ratio of approximately 0.9x for the quarter and approximately 1x on a LTM basis. Coverage for the quarter was impacted by the seasonality of cash G&A expenses, which as I have noted in past calls, is generally higher than the first half of the year due to annual shareholder meeting and compliance costs.

We expect quarterly cash G&A cost for ATLS to continue to moderate from the $3.9 million recognized during the first quarter through the remainder of the year, a range between $8.5 million and $10 million for the full year 2014. We expect to maintain a 1x coverage ratio on cash distributions at ATLS on a rolling four quarter basis in future periods.

Finally, I would like to quickly mention, ATLS has a strong standalone balance sheet at year-end or at the end of March, which as $13 million of cash and an undrawn $50 million credit facility, along with leverage of 2.5x.

With that, I thank you for your time. I will return the call to our CEO, Ed Cohen.

Ed Cohen

Thanks, Sean. I would like to remind everyone of what Brian explained at the beginning of this call because this ARP conference call is being conducted in the context of a securities offering of ARP common stock that was launched last night. We have to abide by securities regulations that limit the subjects that can be discussed in the nature of such discussions. Accordingly we will be able to comment only on subjects related to the ARP and ATLS results for the first quarter of 2014 and the items covered in our public announcement concerning the Colorado oil properties acquisition. Accordingly, questions should be limited to these topics.

And with that caveat, Eric, we are ready for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And our first questions from Ben Wyatt of Stephens. Please go ahead.

Ben Wyatt - Stephens

Hi, good morning guys.

Ed Cohen

Hi, Ben.

Ben Wyatt - Stephens

Just kind of one question around the acquisition and first of all, congrats on the announcement yesterday, but you guys have leaned a lot – the acreage was more geared towards gas, a little surprised to see an oily acquisition even though it's a good thing maybe just because of the backwardated curve or I have heard that the maybe the bid as spread between [Barren and Filler] (ph) just a little too wide.

Just curious, what you guys think, is this kind of a one-off or can we see you guys even be a little more active on the oily side?

Ed Cohen

I think our effort has been directed increasingly to increasing our oil content Matt spoke about that in detail. And so since we are only speaking about the past, we will have to use the past as a guide to what may occur in the future.

Ben Wyatt - Stephens

Got you. And then maybe kind of stand on the acquisition front, Matt mentioned that you guys are now in – and I believe 14 different states, cover a lot of different areas. Maybe just give us a sense of how much bigger you guys could be as far as expanding that footprint, just your comfort around that and maybe just your thoughts around how much bigger you guys could get as far as just your extent across North America?

Ed Cohen

I'm afraid Ben; once again, we are constrained by this historical orientation of this call. I think you know that it is a matter of principle we try to avoid ever being promotional, but I think the past once again will have to be a guide to what might occur in the future.

Ben Wyatt - Stephens

Got you. I will try one more. Nothing to do with acquisitions or anything like that, but Matt also mentioned that you guys run some seismic, just curious if you had any updates on I believe you guys are shooting some seismic in the Marble Falls, any updates on that front?

Ed Cohen

You are getting A for that question. And Matt going through that, okay?

Matt Jones

Yes. We recently shot substantial – an additional substantial portion of our 75,000 acres in the Marble Falls and the shot was from our point of view based on geological characteristics that we hope to see that we now understand we desired to see the Marble Falls far better than even in the past, the shot was a successful one. We believe that I suppose have to be careful about forward statements here, but we believe that the shot revealed to us that within the area covered by the shot we have – we believe to be substantial and highly desirable drilling locations.

Ben Wyatt - Stephens

Very good. I appreciate it. And congrats again on the announcement yesterday and the quarter.

Ed Cohen

Thanks Ben.

Operator

Our next question comes from Praneeth Satish from Wells Fargo. Please go ahead.

Praneeth Satish - Wells Fargo

Hey, guys. Good morning. Just a couple of questions, I guess the first is, I didn't see any mention of the distribution guidance at ARP. So I guess the first question is that guidance still valid?

And the second would be, if you aren't getting credit in the stock price would you consider I guess just passing distribution growth to built coverage or what are your thoughts around that broadly?

Sean McGrath

Well, Praneeth, just because of the nature of the call as Ed and Brian talked about, I will say that our last quarter comments we did reaffirm guidance $2.40, $2.60. So we can't publicly give any update to that guidance, right now or talk any more about that. But I think your point is well taken. We believe that we will execute on that strategy and think that we will be able to continue, we will continue to trade better as we execute on that strategy.

Praneeth Satish - Wells Fargo

Okay. And then how should we think about maintenance CapEx for the Chevron acquisition looks like the decline rates very low. So is it fair to assume the maintenance CapEx, I guess is a percentage of EBITDA would be lower for this acquisition than companywide?

Sean McGrath

Generally, when we look at maintenance capital, I think as we talked public on calls before, its more reflect of the overall decline. So the maintenance capital will reflect that low decline. So I think generally, as you have seen from historical assets it will match the decline. So we will recognize that maintenance capital according to that – those percentages.

Praneeth Satish - Wells Fargo

Okay. And I guess last question for me, so – one of your peers announced a strategic alliance to the large E&P company that basically trade a drop down story. Is that something you guys would consider, I know you have a close relationship with Chevron for example?

Ed Cohen

That's exactly the kinds of subject we can't comment on unfortunately.

Praneeth Satish - Wells Fargo

Okay. Very good. Well, thank you for answering these questions then.

Ed Cohen

Thank you.

Operator

Our next question comes from Michael Gaiden from Robert Baird. Please go ahead.

Michael Gaiden - Robert Baird

Gentlemen, good morning. I will try to keep my comments on the fairway here. Can I ask, expecting that the adverse operating conditions caused by the weather in the first quarter. Can you give us a sense – maybe you could outline perhaps monthly production in January, February, March. So we can sort of understand the severity of that weather impact and how are the partnership have recovered as the winter weather abated.

Matt Jones

On a monthly basis, January and February, particularly February was the month that was where we experienced the greatest interruption of the three months in the quarter – our quarters were impacted by weather. We carefully charted what occurred during the first quarter active weather phenomenon. And we have a pretty good handle on what occurred – where it occurred, how we were impacted, we are working on attempting to better prepare ourselves for that sort of phenomenon in the future.

But February and the three months was the months of the greatest impact. We started to recover particularly in the Marble Falls late in the third quarter as we started to exit the third quarter particularly the last ten days or so, March we started to recover volumes, we started to connect wells that has been shut in. These are oil wells, so it takes some time to get the oils – get the oils operating profitably following the events that occurred.

So as I mentioned, moving into April, we are seeing a nice pick up particularly in oil production and liquids production in our company much of that is related to the Marble Falls improvement in – with respect to the weather events that occurred and also by the way with the connection of some very nice wells recently in the Marble Falls.

Michael Gaiden - Robert Baird

Well, thanks for that color. Ed, can I ask you some follow up? Matt, can you give us any sense of the March exit rate of production or the total months of March production rate?

Matt Jones

It was marginally higher than the average for the quarter, I would say to give you some context. I don't have a number in front of me that would provide detail with respect to state the final date of the production in March. But, I can tell you that last 10 days in March particularly the last few days, the exit rate was marginally higher than the average rate for the quarter.

Michael Gaiden – Robert Baird

Great. Thank you. That's more useful. Can I lastly ask a question about your Mississippi Lime position, can you talk about what's enabled you to continue to exceed type curve expectations under recent well there? That's it for me. Thank you.

Matt Jones

Well, I really greatly appreciate that question because it gives me an opportunity to thank I hope and presume some of the people from our company who are on the call. But it gives me an opportunity really to extent the thanks and gratitude to really an outstanding effort from geology and geosciences staff and our asset management in the Mississippi Lime who have really done an extraordinary job of creating a asset play for us in the Mississippi Lime that's been outstanding.

Our expectations remain quite high, for our acreage in the Mississippi Lime, we really think it's a confluence of geology work well done; asset management drilling and engineering work well done. And acreage that is well-positioned and what we think is one of the core positions in the Mississippi Lime flank.

Michael Gaiden – Robert Baird

Great. Thank you, Matt.

Matt Jones

Yes, sir.

Operator

Our next question comes from Majid Khan from Tourbillon Capital. Please go ahead.

Majid Khan - Tourbillon Capital

Hi, guys. Thanks for taking…

Ed Cohen

Hi, Majid.

Majid Khan - Tourbillon Capital

Congratulations on the various recent activities in the complex. I will try and stay away from the ARP questions but – just maybe if you will allow one quick one if the transaction were to suppose, what does it do to the overall decline side of ARP?

Sean McGrath

Because the limitation in talking forward up here Majid and we apologize for that. But, its tough to kind of give any clarity with regard to that but may obviously we talked about the asset, I think we probably talked about our overall existing decline of assets. So this acquisition obviously will benefit that. We will benefit on our overall decline rate. But it's tough to get that forward-looking amount of pro forma.

Majid Khan - Tourbillon Capital

Fair enough. All right. Let's cross off, next week, I shouldn't.

Ed Cohen

We hope to hear from you on the next call.

Majid Khan - Tourbillon Capital

Well, I do have a few more if you allow.

Ed Cohen

Of course.

Majid Khan - Tourbillon Capital

Maybe if we could talk about your Eagle Ford assets that APL as it relates to ATLS, obviously a testament to the brilliance of the equity market when you guys did this transaction. It was viewed quite favorably. And less than a year later, we are pretty convinced that it's the worst deals since AOL Time Warner.

I'm just wondering if you wouldn't mind giving us your thoughts on the supply/demand for G&P and the basin. The way I see it, there is about 700 to 800 Mcf a day of capacity in the basin. And if the basin is growing about 1 Bcf a day, is it fair to assume that supply/demand should be fairly balanced by the end of the year absent new build announcement. Are there any other puts and takes especially given some of the headlines we have been seeing on the potential asset field in the Eagle Ford?

Ed Cohen

Good question. Good commentary. And I'm hopeful that the deal will shortly be seen as the finest deals since the amalgamation of Ukraine and the Soviet Union. Seriously though, you really put the elements there, the production we think is picking up there have been a number of major players who for coincidental reasons have not been active and they either have or in the process of selling to others. We think the buyers will likely ramp-up as the original intention of the original holders was and that this will restore the tremendous growth in the Eagle Ford.

We think that whatever dislocation there is, is quite – is going to be quite short in duration and for those who listen to the APL call, they learn that the first plant is 70% from an economic point of view already in utilization and shortly will be at an 100% in other plants called for and with the huge customers that we have in the orders that were anticipated one can see that filling up very quickly.

I think in fact, the Eagle Ford, and I know its very common to speak about our Permian situation in West Texas is being the finest processing situation in the world expect for those people who think that the combination of the element Arkoma in Southern Oklahoma challenges even the West Oklahoma situation as I indicated.

The plants are all at 100% capacity, four new plants coming on and so forth. But, well, we love all of our children. My expectation is that we would not be surprised if they go for a – go down is the best of our situations.

Majid Khan - Tourbillon Capital

Thank you for that. I'm glad you brought up the Permian. I noticed that one of your large counterparty this week had great earnings and they continue to forecast 15% to 20% growth throughout the year.

And given your 17 to 18 year contractual agreement with Pioneer and the Basin, given the growth trajectory, when I look at this asset and see where it could be in 5, 10 years, on a standalone basis, I'm kind of confused where what the valuation, the complex of doing. And you using fairly conservative assumption that seems to me that your Permian position alone is worth almost the entire market cap of APL. And at least half the market cap of ATLS.

And I'm hoping the other APL assets are going to at least cover the value of your debt, 5x, 6x EBITDA. So given that so many of your assets are still complementary to may of your larger growth challenged peers and certainly the valuation of the complex is fairly attractive. I guess my question is, you generally agree with this valuation framework for the Permian asset and if so, if the market doesn't recognize the economic and strategic value of your assets, I'm wondering what's the willingness to explore somewhat more creative strategic alternative.

Ed Cohen

Well, of course, we should point out that nothing in your question relates to ARP --

Majid Khan - Tourbillon Capital

Yes.

Ed Cohen

And we are only talking about ATLS and the APL situation. And far from my agreeing with you because some people may think that I'm a self interested party of just note that there a number of commentators who have shared your valuation obviously, given the abysmal state of APL's stock price in our opinion. You are not alone in the – yours is not the only opinion there.

I can take this opportunity to replay to Scott Sheffield, the CEO of Pioneer who yesterday rebuked me of only anticipating a new plant a time period of a year or more. I understand that Scott indicated that from Pioneer's point of view. APL may have to be introducing new plants every 9 to 10 months for the foreseeable future in the Permian.

So with that kind of growth and with the enormous profitability that growth brings with it, it really is difficult to understand market pricing but given the nature of this call, I'm not going to comment any further as to what we might be doing in response, if that situation continues.

Majid Khan - Tourbillon Capital

All right. Well, thank you for your time. And keep up the good work.

Ed Cohen

Thanks Majid.

Operator

Our next question comes from Craig Shere from Tuohy Brothers. Please go ahead.

Craig Shere - Tuohy Brothers

Hi, guys. I will do my best to avoid landmines here, but cut me off quickly, and we can go to the next, if I hit any. Ed, can you comment at all about progress at AGP?

Ed Cohen

I can't.

Craig Shere - Tuohy Brothers

Okay. Sean, can you discuss how nat gas price improvements maybe aiding and depending revolver redetermination as you think about your liquidity?

Sean McGrath

Sure. Craig as you know, often I comment for this just with everything is going on is that, our gas price has had improved during the first quarter that had a very good impact during the first quarter. However, as we've seen, the five year curve, prices are recovering nicely, but they are still at a point level and reminder that the banks use their own price tag when they are evaluating their revolver. So while prices have improved slightly with the banks, so are more conservative generally and how they use their price curves to determine the (indiscernible) determination?

Craig Shere - Tuohy Brothers

Okay. Fair enough. We got a discounted future stack because there is no national buyers out there and then the banks are just telling that. That makes a lot of sense.

Ed Cohen

Yes. Yes.

Sean McGrath

It doesn't make a lot of sense business wise, but yes it makes a lot of sense in understanding that one.

Craig Shere - Tuohy Brothers

Matt, I know that things have been pretty busy, but do you or your team noticed the SandRidge's comment about a single dual stacked tail lateral in the upper and lower Miss that, I think and $6 million have reduced cost by $800,000. Is that something that could have implications for what you guys do either in terms of cost reduction or accelerating production?

Matt Jones

Without question, and we are looking at the opportunity to exploit stack pay on our 20,000 plus acreage Craig. And I think that, you know and perhaps many on the call know that our acreage in Alfalfa, Grant and Garfield Counties is contiguous, is blocked up. But offsetting our acreage, we're kind of in the middle of some acreage that SandRidge is aggressively developing and others around us are developing.

We of course as you can imagine are aware of all that is occurring in the industry particularly with SandRidge's efforts in our area. In addition to the stack pay within the Mississippi Lime there is a shallower formation that we're reviewing from a geological point of view. Also offsetting our acreage not too far from the East and a little bit to the South, there are companies that have drilled very successfully some Woodford Shale wells.

And so we think there is an opportunity to potentially create far more value than we had originally anticipated from Mississippi Lime acreage from the stack pay opportunity. And recall obviously, and I know you know this, all of our acreage in the Mississippi Lime, the great majority of it benefits from infrastructure that has been developed that exists. So that as we add potential stack pay opportunity, we're adding that in an area where we'll benefit from developed infrastructure and that incrementally economics from drilling stack pay could be quite powerful for us.

We're not ready to move in the direction yet, developing our assets from that point of view, but we are quite aware what's happening around us and really pretty excited about what we're seeing.

Craig Shere - Tuohy Brothers

Great. And just maybe tiptoeing in rough territory, but it is definitional question. On the $25 to $30 per BOE Rangely field acquisition LOE cost guidance, is there any capitalized CO2 procurement does not included in that?

Sean McGrath

Sorry Craig, can you repeat that question?

Craig Shere - Tuohy Brothers

Yes. I'm trying, EURs always not the simplest accounting treatment to understand companies may capitalize and expense, different amounts of CO2 injections. And I'm trying to understand if the $25 to $30 per BOE, LOE guidance in your press release included all CO2 acquisitions of these extra amounts that are capitalized and not included in those costs?

Sean McGrath

All the CO2 is included in that BOE number and the production cost.

Craig Shere - Tuohy Brothers

Okay. That's great. And just let me take one more step further on this. Do you believe that you have sufficient CO2 supply under contract to already be able to evaluate with Chevron, the undeveloped portion of the play, or will that involve the need to acquire new supply?

Sean McGrath

Without making any comments on forward periods, we do believe that we have sufficient CO2 supply to execute our strategy.

Craig Shere - Tuohy Brothers

Great. And if I may just one last one, Matt, you highlighted and added I think in Q&A you underscore that, there is definitely an interest and historical play you certainly with the drill bit gone towards improving your liquids output. The sequential change in the quarter was rather pronounced, I think oil is up 11% and gases are off 5 and 3 quarters sequentially. You've got some moving parts in there though, because looking at the weather and then on top of that are there are issues of bottlenecks and basis differentials in your Marcellus footprint.

So I guess my question is, is the first quarter sequential result in terms of changes in output extreme in your view or would you really like to turbo-charge the liquids relative to gas that might even be tailing off?

Matt Jones

Well, I think that our drilling schedule tells the detail, Craig. We continue to dedicate our capital and our partners' capital in drilling program to liquids rich opportunities. So naturally on the margin as we look forward, we don't want to do a lot on this call, but we've talked about this in the past. As we look forward on the margin, we're going to continue to increase. We expect oil and natural gas, liquids production relative to the dry gas that we're producing.

So the mix of the components or commodities that we're generating on the margin will continue to favor in increase in oil and liquids production relative to dry gas production. We are drilling some, what we expect to be based on our past experience and potentially very high yielding dry gas wells later this year, we'll connect a couple of dry gas wells in the Utica and Columbiana County later in June, which will cause some increase in our dry gas production in those period.

But generally speaking, the vast majority of the capital we're dedicating to drilling is going, it's being dedicated to the areas to provide the greatest return. Those areas remain oil and liquids rich area still on the margin, our production mix will continue to increase for oil and natural gas, liquids relatively to dry natural gas.

Craig Shere - Tuohy Brothers

Understood. I guess the question is, if the Marcellus, do you have any – had some really tremendous results out there, if it were debottlenecked, would your answer change much?

Ed Cohen

Craig, I really think we shouldn't base ourselves on past history.

Craig Shere - Tuohy Brothers

Okay. Thank you so much for the answers.

Ed Cohen

Thank you, Craig.

Operator

Our next question comes from Sean Sneeden from Oppenheimer. Please go ahead.

Sean Sneeden - Oppenheimer

Hi, good morning.

Ed Cohen

Hi.

Matt Jones

Good morning, Sean.

Sean Sneeden - Oppenheimer

Most of my questions were answered, but maybe Sean, can you give us a sense on LOE obviously picked up sequentially, I think in part due to the weather impact, but you maybe perhaps quantify that impact and how we should think about, what the real run rate on LOE was for the quarter?

Sean McGrath

Sure. As I mentioned, our LOE when your looking at the first quarter, let's say compared in the fourth quarter. We had higher severance tax amounts, because of the increase in gas prices, the commodity prices in general. So I think if you can look comparing the two periods I think that was about $0.08 or $0.09 increase. On LOE basis, just as a reminder, we do have timing constraints, think about our LOE it's mostly driven by two things most of the cost are generally fixed. We do have variability in terms of timing of maintenance activity. And then it moves with production volumes, because on an LOE per Mcfe basis obviously is the -- most of this cost are fixed and volumes either go up or go down, you're going to see a significant movement period to period.

So its up to comment about the future periods, I will tell you that as we continue to focus on liquids drilling and seen decline in gas volumes and increase some liquid just because of the mathematics, those cost have an impact. And as you're seeing, I think over the last three quarters historically, you're seeing those things rise as we see oil and liquids volumes increase as a percentage. So it's tough to make a comment about what our future periods has given, the parameters of the call.

Sean Sneeden - Oppenheimer

Okay. And that's helpful. And then maybe just one quick one on the balance sheet, at quarter end, it had $365 million liquidity and I think you said around 3.9x times levered. How do you guys think about keeping leverage on, I guess 4x, I think in the past you guys have talked about working on that, obviously you guys were over 4x last year?

Sean McGrath

Correct. I think as I mentioned on our last call, aren't just talking about historical comment. We did say that we expect to exit 2014 below 3.5x. And as I mentioned on that same call, we also said our long term goal is below 3x. So we believe that, we looking towards executing on that strategy and I think is the – we hit our guidance numbers that we provide on last quarter call, we'll be able to get within those ranges.

Sean Sneeden - Oppenheimer

Okay. Perfect. Thank you very much.

Operator

Our next question comes from Noel Parks of Ladenburg Thalmann. Please go ahead.

Noel Parks - Ladenburg Thalmann

Good morning.

Ed Cohen

Good morning, Noel.

Noel Parks - Ladenburg Thalmann

Just a couple of things I certainly wanted to catch up on, in the Marble Falls where the things stand with the trends basic assumptions and testing of any further down spacing?

Matt Jones

It's good question and Noel as you know we have something like 75,000 acres across our position. And the spacing what we have discovered, the spacing will vary from subarea to subarea within our acreage. We're still determining ultimately what level of down spacing we can achieve, we have in some cases tested that. We're seeing some communication between wells, the migration of fluids can be different from one area to the next. And we really haven't set it upon yet ultimately the extent to which we can down space on the acreage.

I think one thing that is clear to us, I know, when we mentioned this earlier on this call, especially with the additional 3D seismic we just shot, we have quite a few remaining very attractive location to drill on the acreage as we continue to drill and analyze what occurs in the subsurface with the acreage, with communication among wells to the extent that happened. We'll report on that and give a clear sense, as time goes on as to what we think the best ultimate spacing maybe for the property.

Noel Parks - Ladenburg Thalmann

Okay. Fair enough. And shifting to the Raton, the CBM projects, a few quarters in now with operating that, I'm just curious, they have economics and just -- the data sort of realized still hanging fruit there for maintenance and so forth. And those essentially met expectations, exceeded or not met expectations?

Matt Jones

Well, in general production has met or exceeded expectation. We are reviewing, I think we had mentioned this a quarter or two ago that embedded in our budget for 2014 was the assumption and that we would invest to a degree in some compression projects on the property. We are reviewing and continue to review these projects from a mechanical and an economical point of view. We do think there will be opportunity to exploit as you refer to it know-how low hanging fruit on the property.

What we have seen so far is that production has been stable without really addressing some of the opportunities to enhance production through compression style projects. We do have work over rigs running on the property, we have found ways to improve production of existing wells and existing positions that we have. We think we'll continue to do that. And we will obviously install compression to the extent the mechanics allows us to do so, electrical capacity allows us to do so and the economics of installing new compression make sense for us.

Noel Parks - Ladenburg Thalmann

Great, and just one sort of broader question as a realty check. Could you picture [EUR] (ph) assets, secondary, tertiary production as being in the drilling partnerships or certainly would you think just more straightforward primary development is the only thing you'd really one of those?

Ed Cohen

That's an area we can't comment on this call.

Noel Parks - Ladenburg Thalmann

Good. Fair enough. That's it for me.

Matt Jones

Thanks Noel.

Operator

And there are no further questions. I would like to turn it back to Mr. Ed Cohen for closing remarks.

Ed Cohen

Thank you all for your patience and understanding. I'm hopeful that on our next call we'll be free of some of the constraints that applied to today's call. Thank you very much. Bye-bye.

Operator

Ladies and gentlemen, that does conclude today's conference. Thank you for your attendance. You may now disconnect. Everyone have a great day.

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