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Atlas Energy LP (NYSE:ATLS)

Q4 2013 Results Earnings Conference Call

February 28, 2014 09:00 AM ET

Executives

Brian Begley - VP of Investor Relations

Ed Cohen - Chief Executive Officer

Matt Jones - Chief Executive Officer, ARP

Sean McGrath - Chief Financial Officer

Mark Biderman - Director

Daniel Herz - SVP, Corporate Development & Strategy

Analysts

Noel Parks - Ladenburg Thalmann

Michael Gaiden - Robert W. Baird

John Ragozzino - RBC Capital Markets

Craig Shere - Tuohy Brothers

Sean Sneeden - Oppenheimer

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter, Atlas Energy LP and Atlas Resource Partners LP Fourth Quarter Earnings Conference Call. My name is Lucie, and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will facilitate a question and answer session towards the end of the presentation. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today Brian Begley, Vice President of Investor Relations. Please proceed.

Brian Begley

Good morning, everyone and thank you for joining us for today’s call to discuss our fourth quarter and full year results.

As we started, 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 addressed our expected future business and financial performance and financial conditions and often contain words 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, which will be filed later this afternoon. 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 revisions to forward-looking statements that may be made to reflect events or circumstances after the date hereof or reflect the occurrence of unanticipated events.

Now in both our Atlas Energy and Atlas Resource earnings releases, we provide a GAAP reconciliation and a non-GAAP measures we refer to in our public disclosures. I'd also like to note that as of today, Atlas Resource partners 2013 K1 tax forms are now available on our website atlasresourcepartners.com, and the Atlas Energy K-1 forms will be available online at atlasenergy.com next Friday March 7th. Lastly we’ll be participating in several upcoming investor conferences including the Morgan Stanley Corporate Access Event in New York on next Tuesday March 4th, The Capital Link MLP Forum next Thursday in New York March 6th, and the IDAA New York Conference on Monday April 4th.

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

Ed Cohen

Thanks Brian and hello everyone. My message today really can be briefly summarized. For the Atlas Energy group of companies 2013 was a good year, although not without challenge and 2014 should be even better. The information and guidance that we’ll provide on this call however is somewhat static, but assumes no benefit from fresh initiatives such as the extent of reworking of wells that we’re undertaking, the work from acquisitions, work from now unscheduled expansions that may position our companies for improved results in 2014 and for even greater success in 2015.

Now let me speak tangibly. I am frankly quite disappointed that Atlas Energy, ATLS shares have declined in price by about 7.5% during the past three months. Although I should point out that ATLS total return to unitholders for 2013 was about 39% and ATLS’s total returns about 275% during the past three years ending December 31, 2013. That’s roughly the period since the Chevron sale. It does represent one of the highest returns in the entire world energy industry for that period. But of course I am also unhappy about the performance of Atlas Pipeline Partners APL which is down about 12% during the past three months. That’s the decrease that has in turn adversely impacted the price of ATLS stock. The slight rise about 4% in Atlas Resource Partners ARP shares during the past three months is really slight solid.

But the reality is just supply I think optimistic expectations for the near and further future, both intangible accomplishments [and that] return to unitholders. Let me speak first briefly about APL and then in laying about ARP and ATLS. APL’s stock price has been pummeled by investor disappointment over APL’s failure immediately could go enthused over a plant South Texas and by a lackluster results at it Arkoma division in South Oklahoma.

These are in my opinion stringent difficulties use of the past and should not committed to obscure the fact that APL has state of the art processing plant easily scalable and most importantly located in the greatest natural gas liquids NGL growth areas in North America, in the Permian and Eagle Ford Basins in Texas and in the SCOOP and Mississippi Lime areas in Oklahoma.

In APL’s quarterly call last Tuesday pipeline management explains all these operational difficulties of being installed. Our Silver Oak I was being filled and had a new pipeline connection between APL’s Velma and Arkoma facilities will sharply enhance results both at Arkoma and Velma. Velma by the way already is quite profitable, but without this new connection providing access to new processing capacity at Arkoma, Velma’s burgeoning natural gas intake, which shortly has exhausted Velma’s process at.

But the bigger picture at APL should not be ignored. In the Permian basin in West Texas, which today with the shale revolution is perhaps the world’s fast growing energy producing area and already perhaps the second most prolific play in the world, after the central production areas of Saudi Arabia. There APL has been in the process of adding a new 200 million cubic feet day process plant every 18 months and that’s just to keep up with the customers burgeoning production. Now that pace may actually accelerate to speed up is likely to continue for years in the future. Every new Permian plant filled being about $65 million.

An additional EBITDA per year, per plant, like the tremendous return on a cost of about $125 million for the new plant which with associated infrastructure can reach a total of $180 million per plant, as $180 million per plant.

And the Eagle Ford in Southern Texas is running the Permian at close [race] for growth. It’s hard for me to believe that APL’s lead investment of $1 billion in the Eagle Ford will not yield blockbuster income shortly and for many years to come in the future.

Now there is the SCOOP that’s the South Central Oklahoma Oil Province. SCOOP and Arkoma production which is exciting the world, provides the basis for great results in APL southern Oklahoma division. And the Mississippi Lime is similarly versioning in western Oklahoma, where volumes in the fourth quarter were 538 million cubic feet per day, an astounding 23% increase over the fourth quarter of 2012.

And now on top of all that, the former CEOs of Chesapeake and SandRidge through their new funds are reported to be in the process of investing yet more billions of dollars in the Mississippi Lime areas of Oklahoma and the joining states, augmenting the huge investment programs of their former companies and others and ordering the possibility of even more growth and even more profit for APL and presumably more incentive that is IDR income for ATLS as general partner.

Now the Mississippi Lime of course is where Atlas Resource Partners, ARP continues to yield strong levels of oil and liquid production. There as in the Marble Falls, the Utica and the Marcellus Atlas Resource Partners has achieved increasingly favorable results.

For example, the threefold increase year-over-year and high margin oil production. Items which ARP’s CEO, Matt Jones will shortly discuss in detail.

In fact, ARP’s SEC based year-end reserves reached approximately 1.2 trillion cubic feet equivalent. That was a 61% increase over year end 2012. As a result of sharply increasing income, thus generated from the bid and from successful acquisitions, the important Raton and Black Warrior assets acquired a little over year ago have performed even better than our projections.

ARP has now increased quarterly distribution to $0.58 per limited partner unit for the fourth quarter 2013, a 4% increase from the prior quarter and a 21% increase from the corresponding year earlier period.

Adjusted EBITDA increased to $62.6 million for the fourth quarter compared to only $31.8 million for the prior year comparable quarter. ARP’s adjusted EBITDA was $206.8 million for the full year 2013 compared to only $84.5 million for the full year 2012.

Attributable cash flow in turn was $41.0 million or $0.58 per common unit for the fourth quarter 2013, compared to $27.5 million for the prior year comparable quarter with a $149.1 million for the full year 2013, compared to $64.1 million for the full year 2012.

I’m glad that I was listening when my first grade teacher was teaching arithmetic, but those numbers I see are really good. Also as a result of these favorable results and trends, ARP is reaffirming guidance in the range of $2.40 to $2.60 per common unit for the full year 2014.

And progress continued. Just two weeks ago on February 14th, ARP announced that it has agreed to acquire approximately 70 billion cubic feet equivalent approved reserves of natural gas in West Virginia and Virginia from GeoMet for $107 million with an effective date of January 1, 2014.

Transaction is subject to customary conditions, including approval from GeoMet’s stockholders with the company’s largest shareholders legally obligated already for transaction. This mature low-decline production is expected to be immediately accretive to ARP distributable cash flow per unit. Current net production from the asset is approximately 22 million cubic feet equivalent per day from over 400 active wells, with the current expected annual decline rate of approximately 10% to 12%.

The GeoMet acquisition is thus highly compatible with ARP’s policy of operating long live low-decline reserve, a policy that had already been enormously advanced on July 31, 2013 by the much larger acquisition from EP Energy of some 3,000 seasoned producing wells, principally in the Raton Basin in northern New Mexico and the Black Warrior Basin in Alabama.

EP acquisition substantially reduced our annual decline rate, thus effectively minimizing future expenditures required to maintain revenue, so called maintenance CapEx. Now, the anticipated addition to GeoMet assets will further consolidate ARP’s already low rate of decline on producing assets.

I should also allude the success of our syndication program. 2013 investment program raised $150 million, an increase of approximately 20% over the prior year. The present year’s program is now budgeted for a raise of $200 million. Besides generating substantial fee income for ARP, drilling and completion of wells for these programs helps ARP to maintain an elevated level of expertise and experience in various aspects E&P business and that’s mutually advantageous for investors and for ARP itself.

Turning to Atlas Growth Partners, our new entity at ATLS, fund raising for AGP has moved into high gear. A highly experienced and successful sales staff has been recruited and did this work. We have now increased the size of the offering from its original $300 [million] to $500 [million]. Atlas Growth now has committed rig running on its acreage in a Marble Falls area with three wells producing already, two more wells drilled and completed and currently cleaning up through flow back, a further well now drilled to total depth and an additional well currently in the process of being drilled. Initial distributions at a 7% annualized rate have been paid to initial unitholders.

ARP has also introduced its new monthly distribution policy, declaring an initial distribution of $0.1933 per common unit for the month of January 2014, monthly distribution policy which is more demanding as ARP’s [backlog is] has listed at a favorable response from unitholders.

Let me finally say a few words directly about ATLS, the general partner of ARP, of APL and now of Atlas Growth Partners and the part owner of the general partner of Arc Logistics, the company newly admitted to trading on the New York Stock Exchange under the symbol ARCX.

ATLS has to clear a cash distribution of $0.46 per limited partner unit for fourth quarter of 2013, that’s an increase for Atlas Energy of $0.16 per unit or 53% over the prior year fourth quarter.

Based on distribution guidance previously provided by subsidiaries, ATLS now expects distribution to unitholders in 2014 to grow to a range of $1.95 to $2.45 per common unit. This represents at least a 20% increase compared to full year 2013 distribution.

Well, I’m finally finished. And now Matt Jones will discuss energy activities at ARP, after which Sean McGrath, our CFO will cover financial results for the last quarter of 2013 and for the full year 2013. Matt, take it away.

Matt Jones

Thank you, Ed and thank you all for joining our call. The fourth quarter of 2013 includes another year of outstanding growth at Atlas Resource Partners. Over the course of the year, we increased our total net production by roughly 100% including a threefold increase in high margin oil production. Not only have we greatly increased our production, but we’ve also significantly diversified across basins in region and materially lowered our portfolio decline rate, bringing adjustability to our production stream. The total production increase was a key factor in our peer leading cash distribution growth rate of 21% for the fourth quarter of 2013 compared to the fourth quarter of 2012.

So what’s behind the numbers, our track record results from both acquisition and organic growth, including the effective acquisition and the simulation of high quality producing assets, the exploitation of liquids rich and high yielding dry gas locations and the growth in our development and operating activities for our investors and our drilling investment programs.

It is my firm belief that our company is better positioned today to execute our growth focus business plan and develop and manage our attractive assets compared to any other time in our history.

We are better positioned to expand the areas of our business that have performed well and to address the areas where we believe we can improve. Key to that belief is an all important element that I have embedded for the witnessing everyday and that is the collective experience talent dedication of our employees. This important element manifests in many of the exciting aspects of our business that we’ll address in a moment.

First of all I would like to recognize and thank all the men and women of Atlas for their dedicated efforts in 2013 and into 2014 especially those who battle through incredibly harsh winter weather conditions of the recent past to keep our wells flowing and our well drilling and completions operations functioning as best as humanly possible.

Our fourth quarter results would have been even better not good as obvious and uncontrollable factor and our first quarter production will be impacted as well. However, with extreme weather conditions recently waiting, our production results are moving higher and we expect continued progress through the remainder of the quarter.

Our multi-level growth approach continues to progress on all fronts. I recently announced definitive agreement to acquire approximately 70 Bcfe or below decline crude develop producing natural gas wells procurement, further diversifying our production stream and fits very efficiently into our coal-bed methane segment where we’ll lever our company’s core knowledge of CBM asset. The assets also include 30 or more potential drilling locations all held by production and we’ll add these locations to our wide and [varied] list of future drilling options available within asset base.

We also anticipate bringing onboard the GeoMet field operations team. This is a team that has worked these assets for many years and we look forward to welcoming them to Atlas.

The GeoMet CBM asset acquisition funds our highly successful acquisition of CBM assets in the return of Black Warrior Basins from EP Energy last year. The low decline assets acquired from EP continue to perform at or above our acquisition expectation and our CBM asset team is focused on bringing forward economically efficient way to continue to enhance asset performance.

For example, we have budgeted in 2014 added compression and recompletion activity and that could have a dual benefit in resting already low decline rates and providing very competitive returns compared to other projects. We believe that the compression project will have the payback period of less than 9 months with anticipated increased production coming from wells and infrastructure that are already in place.

As pleased as we are with the performance of our recent acquisition, we are equally excited about recent well performance in our current development areas. Our drilling program remains diverse and highly concentrated in oil and liquid rich areas. It’s our belief that our focus on exploiting liquids, enhanced drilling location allows us to efficiently replace natural declines in our producing assets and provide an attractive core drilling prospects for our company and for those who invest in our drilling program offering.

For our Mississippi Lime position, we connected 4 wells in the fourth quarter all in the month of December and we now have 60 days of production history reaching the well. On average over the 60 days period, the wells connected in the fourth quarter produced 484 BOE per day, materially exceeding our type curve for this period of 283 BOE per day. Of equal importance, the composition of the production is roughly 50% liquid also exceeding our type curve for the 125 barrels of oil and 115 barrels of NGLs produced on average per production day.

While the results from these wells alone will be exciting and encouraging, what is perhaps more significant is the trend that is developing with our Mississippi Lime well performance. Some on the call today may remember that we had reported the connection of 5 wells in our Mississippi Lime program in the third quarter of 2013 with initial production rates meaningful exceeding type curve assumptions. These wells to-date continue to outperform. These results reflect primarily the diligent efforts of our geology and engineering teams over the last year or so and we’ve advanced our knowledge of the play.

Key advancement includes improved understanding of horizontal lending target maintaining wellbores within target zone throughout the lateral and more efficient better completion techniques. We’ve also lowered our drilling and completion cost further improving our capital efficiency in the play. Our well costs now generally range from $3.6 million to $4.5 million per well with the range reflecting the variant cost associated with drilling to the shallow versus deeper section of the formation.

All of our well drilling activity in the Miss Lime in the third and fourth quarters of 2013 and continuing into the first quarter of 2014 has been funded through our 2013 Series 33 Direct Investment program. Important to note that ARP owns an approximate 33% interest in the Series 33 program so we’re pleased to provide updated information for ARP common unitholders, as well as those who invested directly in the program.

For our capital program for 2014, we’re prepared to utilize two rigs on our Miss Lime property through the course of the year and we currently have 2 rigs running dedicated to the completion of wells in our Series 33 program. Through the end of the second quarter of 2014 we’ll finish the Series 33 wells, drill an additional saltwater disposal well and initiate drilling of several Miss Lime wells for our company’s direct interest. We also planned to initiate Miss Lime drilling associated with our 2014 Series 34 Direct Investment program late in the second quarter and continued through the course of the year for the Series 34 program.

In total we plan to drill and complete 22 wells on our Miss Lime position in 2014 for our Series 34 program and for our company’s direct interest. In addition to this we will complete 8 wells for our Series 33 program to finish up that program in the first half of the year.

It’s worth noting that SandRidge Energy, the most active driller in Miss Lime play will invest in a number of our wells in 2014 as the non-op partner. We also intend to invest as a non-op partner in a number of SandRidge operated wells. Many on our call today are aware that our Miss Lime acreage position lies in the core of the play located in Alfalfa, Grant and Garfield Counties in -- on several fronts by SandRidge’s position.

Lastly from a field operations point of view, our Miss Lime asset team is highly focused on optimizing water takeaway, a disposal method in electrical rig capacity to maximize, to minimize downtime, maximizing utilization of our existing infrastructure and targeting expansion will increase field efficiencies, as well as add wells as we have wells to our system.

Moving to our Appalachia drilling activity, we initiated development of our Marcellus Shale acreage in Lycoming County, Pennsylvania last year and drilled and completed 8 horizontal wells that we brought online in the third quarter. I am pleased to report that in the first 180 days of production, the wells have produced in excess of 11 Bcf of natural gas or greater than 7 million cubic feet per day per well on average. Today even after six months of production, the wells continued to produce around 6 million a day per well on average. General EURs design to the wells is about 80 Bcf collectively or about 10 Bcf per well.

We’re also happy to report that we have another 15 plus identified drilling locations that offset our enclosed proximity to our producing wells in Lycoming County that we believe will benefit from similar geological characteristics and from infrastructure that we've already developed on our acreage position.

Of course the challenge for Marcellus producers recently has been the volatile [bases] differentials caused by limited pipeline capacity. Limited capacity presents an opportunity for Midstream developers and substantial additional capacity is planned which should release bottlenecks in future period.

In Lycoming, we were priced off the [lighting] index over the last 10 day. Prices have ranged between $4 and $5.20. In fact today, we understand lighting pricing is around $4.44 compared to spot end and the up prices today is about $4.53.

The pricing would average $4 the low-end of the range. Our Arizona identify drilling locations would likely exceed 30% or more. Even if prices average $3.25 which represents average lighting pricing from November 1st to November 27th our Lycoming drilling prospects can generate 15% to 20% returns with expected outcomes reflect a lower finding and development cost and low operating cost associated with the production. Within our 2014 capital budget, we left open the option of drilling several additional Lycoming wells later in 2014, with likely inclusion in our Series 34 drilling partnership program.

In Ohio, please recall in 2013, we developed an acreage position in Harrison County Ohio, where we built a single pad location that was engineered to accommodate 5 horizontal Utica wells in the wet gas window. Following site development, drilling and completion, we brought the 5 wells online in September of last year. Nearly concurrently, a key processing plant caught fire and was taken out of service in early January of this year. Because of the restricted processing capacity and because of wells had a greater proportion of high grade condensate than we had originally anticipated. We flow the wells more slowly than originally contemplated which is lead to steadier state production as compared to high initial production rate cumulatively in the first starting 36 days of production we produced roughly 87,000 barrels of high grade condensate for the wells 17,000 barrels of NGLs and 330 million cubic feet of rest new gas.

Even after the first four months of production, the wells continued to produce at a rate of 400 to 500 barrels of condensate per day, and we anticipate low decline rates moving forward. Currently in the Utica play, we have drilled now nearly finish the completion of 51 frac stages on three wells drilled from a single pad side on our Columbiana County property, where we have roughly 1,200 contiguous acres under lease.

All operations have proceeded according to plan, wells that average lateral length of about 5,400 feet, the wells are being funded through our series 33 direct investment program and we anticipate initial production from the wells in early June of this year and we will provide updates accordingly as the year progresses. Also worth nothing Total is investing in these wells as a non-participant, lastly because of the advantageous configuration of our acreage position here, we estimate that we have an additional eight to nine drilling locations or potentially more than that, that will each individual have lateral lengths in excess of 5,000 feet.

Moving to our Texas operations, we have continue to develop our oily Marble Falls asset where our vertical drilling program allow us to complete multiple zone and see exact pay opportunities including the Marble Falls, Barnett Shale, Bend conglomerates, the Caddo and Chappel Reefs, recent successful wells include wells that we have produced only from the Marble Falls and wells that benefit from stack paid completion.

Our best performing wells today are the stack paid wells and the very recent example include the combination Marble Falls, Bend conglomerates well that has produced nearly 200 barrels of oil per day in its first week of production. During integration of well data, 3D seismic interpretation and improved drilling and completion practices, we're able to maximize the number of highly productive wells and minimize lower productive wells.

Our current Marble Falls drilling activities partially funded through our Series 33 drilling investment program and partially from ARPs cash resources. With two rigs running in the Marble Falls in the fourth quarter, we spud 22 gross wells and 11 net wells and in the first quarter of 2014, we're scheduled to spud 24 gross and 12 net wells.

It is important to note, that the Marble Falls region was the hardest tin among our areas of operations by the November through February weather anomaly. High storms in wells (inaudible) totaling production from existing wells, delayed completion efforts on certain wells and because of road closures prevented water and oil trucks from reaching development areas in both sides.

Having an ordinary experience our Marble Falls team is happy to report the production levels are rebounding and wells completed during this period appear to be within expected ranges, we should have more data to share on our next earnings calls.

Included in our 2014 development plan, we expect to drill 87 gross wells in the Marble Falls with one to two rigs running over the course of the year. The max majority of the wells are scheduled for inclusion in the remainder of the Series 33 program and our forthcoming Series 34 investment partnership program. Also in the Marble Falls and included in our 2014 development plan, we intend to continue to exploit high return on investment, re-completion opportunities in the greater Marble Falls Play. This has composed largely a various bypassed behind of the Bend conglomerates and Marble Falls sections.

Lastly, we announced SEC based yearend reserves of approximately 1.2 Tcfe, representing a 61% increase over year end 2012. The increase resulted from net reserve additions associated with our successful efforts in our Marble Falls, Mississippi Lime, Marcellus and Utica positions and from our acquisition of producing natural gas assets in the Raton and Black Warrior Basin. Offsetting these additions was the removal of 34 Barnett Shale PUD locations totaling 79 Bcfe improved on developed reserves primarily associated with the SEC 5 year PUD development rule. However the locations remain attractive resources for our company and remain within our company’s asset base.

Thanks to all. That concludes my remarks. We look forward to further growth and improvement in 2014. I’ll turn the call to Sean McGrath for the financial review. Sean?

Sean McGrath

Thank you Matt. And thank all of you for joining us on the call this morning. Regarding ARP, we generated adjusted EBITDA of approximately $63 million or $0.95 per unit and distributable cash flow of approximately $41 million or $0.58 per unit for the fourth quarter of 2013.

As Matt previously mentioned we are unfavorably impacted by approximately $2.5 million to $3 million due to lower volumes in ARP’s Barnett and Marble Falls region due to adverse weather conditions during the back half of the fourth quarter.

ARP distributed $0.58 per limited partner unit for the period based upon these results, representing approximate 1.05 times coverage ratio for the quarter adding back for storm impact and the 1.1 times coverage on a rolling four-quarter basis. Adding back the impact of the storms production margin for the fourth quarter was approximately $62 million which represented an 8% increase compared with the $58 million for the third quarter of 2013 and an increase of over a 100% compared with the prior year fourth quarter. Production volumes were approximately 250 million cubic feet of equivalents per day for the fourth quarter compared with ARP third quarter production run rate of approximately 251 million per day. This decrease was principally due to over 6 million of equivalents per day that was impacted because of the storms.

With regard to commodity prices although Henry Hub gas first month prices were approximately $0.05 higher in the fourth quarter of 2013 compared with the sequential quarter. Realized gas prices were $0.17 higher due to higher hedge prices and improved basic differentials at a number of our sales points.

Pricing for West Lycoming Gas that’s lady hub which account for approximately 8% of our total natural gas production average almost $2.85 per Mcf for the current period compared with $2.15 per Mcf for the third quarter of 2013 an improvement of over 30% from the sequential quarter. Although it still reflected a 20% differential from Henry Hub first month pricing of $3.60 for the quarter.

As many of you are aware natural gas price had a dramatic uplift over the past three months as recent storms have caused storage droughts not seen in recent years. Henry Hub first month price for the first quarter of 2014, settled at almost $5 per Mmbtu including the February contract selling at almost $5.60 per Mmbtu.

While our natural gas production is hedged over 80% for the first quarter of 2014, ARP still has approximately 35 million to 40 million cubic feet of natural gas a day which is sold at daily prices, which reduced our results for the first quarter. For example of our Barnett and Marble Falls gas have witnessed average daily prices of almost $6 per Mmbtu for the first two months of 2014 with certain days striking over $20 per Mmbtu.

With regard to liquids oil prices all stayed strong for the fourth quarter as WTI prices averaged almost $94 per barrel. In addition NGL prices, particularly propane were strong during the fourth quarter as we realized $0.73 per gallon compared with $0.69 for the sequential quarter those net of transportation and fractionation expense. Prices averaged $1.20 per gallon for the fourth quarter compared with $1.02 per gallon for the sequential quarter, an 18% increase and have remained strong for the first two months of 2014.

Ethane price has also seen an uplift during the first few months of 2014. But our realized prices have averaged $0.34 a gallon compared with $0.25 per gallon for the fourth quarter of 2013. With regard to our partnership management segment, we raised over 125 million during the fourth quarter and 150 million in the aggregate for 2013, an increase of approximately 20% from 2012.

Partnership margin for the quarter was over $10.7 million which was $2.5 million lower than the third quarter of 2013 due to additional capital deployed on larger wells, such as those in the Utica shale going the third quarter. I would like to mention that we have adjusted EPS, adjusted EBITDA and partnership margin for the fourth quarter to exclude $4.8 million of well construction and completion margin that we recognized under GAAP during the fourth quarter, but earned during the third quarter, which I mentioned in last quarter’s call.

For 2014, our guidance assumed there to raise at least $20 million in partnership investor funds. A 33% increase from 2013 and deployed approximately $108 million of investors’ capital regarding opportunity and fee based margin in 2014.

Moving on to general and administrative expense net cash G&A was a little less than $8 million for the period, which is almost $2 million lower than the third quarter of 2013, which is due to a $2.5 million increase in the capitalization of administrative cost associated with ARP’s 2013 partnership program due to an increase in funds raise from the substantial quarter.

ARP capitalized a certain amounts of a G&A cost associated with the partnership programs as a component of its capital contributions. We currently anticipate ARP’s cash G&A expense for 2014 to be between $38 million and $43 million.

Total capital expenditures were approximately $59.5 million for the fourth quarter of 2013. This included $28 million of CapEx for direct well drilling in the Marble Falls and Mississippi line regions and $17 million investments in our partnership programs.

For 2014, we anticipate ARP’s total capital expenditures to be between $185 and $200 million including $150 million -- $160 million for work over and well drilling activities, including $75 to $80 million of drilling directly to ARP’s account.

With regard to maintenance capital expenditure, I am sorry, and Matt [Technical Difficulty] by multiplying our forecasted future full year production margin by our expected aggregate production decline of PDP wells, which is currently forecasted to be [Technical Difficulty] expect to drill that will generate an estimated first year margin equivalent to that production margin decline.

[Technical Difficulty]

We provide additional details with regard to assumptions utilizing this calculation in the footnotes of our earnings release. We expect maintenance capital expenditures to be between $45 million and $50 million for 2014. With regard to risk management activities, we continue to execute our strategy of methodically yet opportunistically mitigating potential downside commodity volatility for both our legacy and acquired production. Overall, we have hedge positions covering approximately 194 billion cubic feet of natural gas production at an average floor price of over $4.25 per Mcf for periods through 2018.

In addition, we have hedged in average of approximately 100% of our current run rate crude oil production through 2015 at an effective average floor price of approximately $90per barrel, with additional hedges through 2017.As a reminder, 100% of our commodity derivatives are swaps and [choler’s] which simply provide us protection against commodity price movement.

We are committed to continually add protection to our business and provide further clarity with respect to anticipated cash flows. And we’ll continue to do so as we have demonstrated in the past. Please see the tables within our press release for more information about our hedges.

Although it is a non-cash item, I want to note that we recognized $38 million of gas and oil property impairment in our non-core New Albany and Chattanooga Shale region. These impairments consisted of approximately $14 million of expected undeveloped leased expirations in the coming years in New Albany and Chattanooga region as well as the $24 million impairment of our New Albany oil and gas property.

With regard to New Albany oil and gas property impairment, both current and near-term NYMEX gas prices are at or higher than comparable prior year prices. The price tag for 2018 which is required by accounting regulations to calculate the fair value for the majority of the production from this region at December 31st was more than 10% lower than the prior year. We do not expect to have any additional oil and gas property impairments in future periods assuming current commodity prices.

Moving on to our liquidity position and leverage. At the end of December we had approximately $312 million of availability under our $735 million revolving credit facility with the leverage ratio of approximately 4 times. I’d like to point out ARP recognized $47 million of subscriptions receivable on its balance sheet at year end which reflects contributions to its partnership program as of year end for which ARP did not recognize the cash for January 2014.

Pro forma for this cash and the adjusted EBITDA impact from the storms, mentioned previously, ARP’s leverage ratio would have been 3.8 times. We anticipate exiting 2014 with a leverage ratio below 3.5 time and with long-term target at below 3 times level.

In closing for ARP, I’d like to mention that with regard to our guidance for 2014, we anticipate to ramp ARP’s adjusted EBITDA and DCF during the course of the year due to the timing of partnership margin recognition and well connections for our development activity.

For the first quarter of 2014, we anticipate adjusted EBITDA at DCF and cash distributions per unit to be quite similar to the fourth quarter of 2013, excluding the impact on production volumes and margin from the storms and severe weather ARP and others had experienced in the first two months of the year.

With regard to Atlas Energy L.P. we generated distributable cash flow of almost $24 million and distributed $0.46 per unit for the period, representing a coverage ratio of over one-time. This distribution represented an increase of over 50% from the $0.30 per unit distributed for the prior year fourth quarter. Going forward, we expect to ATLS to continue maintain minimum coverage on its cash distributions on a rolling four quarter basis.

Atlas Energy recognized over $9.5 million total cash distributions from APL during the period, representing a 50% increase from the prior year fourth quarter, which included almost $5 million of incentive distribution rates, double the amount from the prior year fourth quarter. ATLS also recognized $17 million of cash distributions from ARP and over 60% increase from the prior year fourth quarter and a 6% increase from the third quarter. ARP distributions for the quarter included approximately $2.1 million from incentive distribution rates compared with the $150,000 for the prior year fourth quarter.

Cash G&A expense for Atlas Energy on a standalone basis was $1.6 million for the period, generally consistent with the previous quarter. As a reminder, Atlas Energy’s cash G&A expense is generally higher than the first half of the calendar year due to seasonal expenses including Annual Shareholder Meeting and compliance costs.

Finally I’d like to quickly mention ATLS strong standalone balance sheet at year-end which is $70 million of cash and undrawn $50 million credit facility along with leverage of 2.5 times.

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

Ed Cohen

Thanks Matt, thanks Sean. I think we have given you a lot to digest but we will now like to open the lines for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And our first question will come from the line of Noel Parks with Ladenburg Thalmann. Please proceed.

Noel Parks - Ladenburg Thalmann

Good morning.

Ed Cohen

Good morning.

Noel Parks - Ladenburg Thalmann

Just a couple of things, speaking about just overall with your portfolio as it has continued to broaden over the last year in particular, where do you see the I guess sort of the most mismatch or gap in terms of the regions where you probably still need some technical manpower, the most sort of I guess over staffed or versus understaffed regions, just wonder where your biggest challenge is regionally as far as that goes?

Ed Cohen

Matt?

Matt Jones

Yes. Hi Noel. I would say the area that presents the greatest challenge for us or the areas that present greatest challenges for us are those where we’re undertaking the greatest growth. And I will say that the asset teams that we have assigned to each of those areas, those teams are doing really a tremendous job, keeping up with the level of drilling that we are undertaking, overseeing the operations, field management operations, making sure that we are ahead of schedule in terms of improving water systems, drilling salt water disposal capacity in anticipation of further growth. But generally speaking, the greatest challenge that we face is simply keeping pace with the drilling activity that’s ongoing in primarily the Mississippi line and the Marble Falls areas. We benefit both of those areas from having people who have experience in both, North Texas, the Barnett Shale and the Marble Falls and in the Mississippi line.

More broadly speaking, our company today has people who are very well experienced in all the regions where we are operating, which is part of the reason I think we’ve been able to successfully bring forward production and in fact do better than we had anticipated with some wells, some areas and with producing assets that we’ve acquired.

And as I said in my prepared remarks, I think we are better positioned today than we’ve ever been. And part of the reason for that is the quality of the people that we have, but the greatest challenge we face today is keeping pace with the development activity that’s undertaking in this area.

Noel Parks - Ladenburg Thalmann

Okay. And since we’ve this -- with the cold winter we’ve seen some [wealth] and improvement in the SPU and also strip, which of the major reasons of your gas production, which ones benefit the most from say, I don’t know, maybe a year ago, we were thinking about I don’t know, $3.50 to $4 strip is being maybe where we be, what we have to assess a little while. And now if we’re looking $4.50 range, that incremental difference, which region do they help the most?

Matt Jones

In terms of…

Ed Cohen

You have to bear in mind that we are heavily hedged, so that affects it. But Sean, were you about to respond?

Sean McGrath

Yes. I was trying to clarify did you mean drilling opportunities which were in regions that offer the more drilling opportunities drill these wells because more wells are economic or you mean just where we are going at the most uplift in terms of pricing per region?

Noel Parks - Ladenburg Thalmann

I think just in terms of economics, some properties of course the difference between 350 gas and four gas is the big inflection point and then others will you get -- were you going to be optimistic or better than before that really helps bring them from just breakeven to much better economic?

Sean McGrath

No, I think that one area that we have that we’ll likely benefit more than any other from higher, essentially higher, realized higher than natural gas prices potentially higher prices going forward is our Barnett Shale position. We have a fair number of quite a few drilling locations in Barnett Shale particularly the dry gas wind of the Barnett Shale where we have drilling sites that are available to us on add sites that have been developed where infrastructure is in place, where we have frankly the greatest, the most outstanding drilling and development team in the Barnett Shale in place, ready to develop those assets for us as soon as the pricing prevails it causes that to be, those assets to be competitive with the other areas where we are drilling.

But the Barnett Shale will clearly benefit from higher natural gas prices. And we have quite a few locations in the Raton area, in the Black Warrior basin area that will benefit from higher natural gas prices as well. And as good as the Lycoming assets are that we have that will also benefit from higher prices.

So we have quite a few drilling locations where we have embedded infrastructures, takeaway capacities in place, infrastructure has been built, pad locations are developed and we’d benefit -- and then available to us with higher gas price is the -- and whether we become competitive with our other projects.

Noel Parks - Ladenburg Thalmann

Great. That's all for me. Thanks.

Brian Begley

This is Brian, just to acknowledge I understand that there is some audio problems on the call in the middle of Sean’s remarks, so we apologize for that. There was an issue with the call service for about a minute or so. We're happy to address any additional questions regarding if it was missed, in the Q&A session here. Thanks.

Operator

And our next question will come from the line of Michael Gaiden with Robert W. Baird. Please proceed.

Michael Gaiden - Robert W. Baird

Good morning gentlemen. Thanks for taking my question. And Brian thanks for acknowledging that drop off. Can I ask, I think your drop off during Sean’s comments about maintenance CapEx. Sean, could you perhaps briefly share with us your comments on maintenance CapEx and maybe you're going to talk about the 2014 outlook for that line item?

Sean McGrath

Sure, absolutely. Yes I mean it’s actually -- during my comments just explain maintenance capital, Ed’s going to explain last quarter just about (inaudible) new people on the call. But I think we've arranged $45 million to $50 million for maintenance capital for 2014.

Michael Gaiden - Robert W. Baird

Great, thank you. And if I can follow-up with a much broader question for both you Sean and the rest of the team there. How do you think about your flexibility for M&A given your goals to reduce leverage this year? Does that goal at all -- is it your ability to continuously active in M&A, if you could frame that for us that would be helpful?

Sean McGrath

Sure, yes. I think we’re looking at the M&A market, there is some great potential out there, we see a lot of good opportunities that will be complementary to our business. Obviously we’re very focused on adding the correct assets with the appropriate decline provide us with the good opportunities that we are seeing.

When we look at financing acquisition I think when you look at history we’ve averaged I’d say probably 60% to 65% of equity on the transactions make sure are conservatively financed. I think if we stick to that pattern when you look at our leverage and you look at the EBIT we have come online with the great drilling activities and that is I think we’re doing. I think leverage will naturally decline during the course of the year. As I said, pro forma for the cash for the partnership programs we were about 3.8 times at this year-end we’re expecting to exit the year around 3.6 times at December 31, 2014 in that range.

So I think with the M&A market I think if we just stick to our conservative approach how we’re financing these, the transactions will both be accretive to Bcf per unit and additionally have to slow our leverage.

Michael Gaiden - Robert W. Baird

Great, thanks Sean. And should I maybe have, how do you see the infrastructure constraints in the Utica and Marcellus abating if at all in the coming year?

Ed Cohen

Well, there are infrastructure projects that are now approved and are being funded by some of the major Midstream companies in the Appalachia Basin. I think that there is going to be some relief coming toward in future period as a result of really great substantial capital investments that’s being made by pipeline companies in Marcellus.

And so obviously all companies that they operate in that region will benefit. One thing is interesting to note by the way your question brings to light, we have had, we have been under restriction in expanding Appalachia because of a non-compete agreement we had persisted from our former transaction that we had done with Chevron a number of years ago.

So that non-competing agreement expired about 10, 12 days ago which was a very significantly event for a company because we have a great deal embedded knowledge associated with Appalachia. We were one of the first developers, the pioneer if you will developing in the Marcellus Shale number of years ago.

We have probably 250 or so wells that we are operating today in South Western Pennsylvania in Green County, Washington County. So we have deep embedded knowledge in the Marcellus Play. We now have had restriction removed limited in our ability to expand in the Marcellus.

In the past we intend to use our embedded knowledge we intend to use the operating leverage that we have in Appalachia to ultimately when the right transactions, right opportunities surface take advantage of all of that.

I think investment will continue from the Midstream side, relief will continue and gas will move around the country to where it’s needed, and I think infrastructure clearly is coming in many projects that have been announced and that are been funded.

Michael Gaiden - Robert W. Baird

Great, thanks Ed and thanks John all for your comments. That’s it from me.

Ed Cohen

Thank you.

Operator

Our next question comes from the line of John Ragozzino with RBC Capital Markets. Please proceed.

John Ragozzino - RBC Capital Markets

Hi good morning gentlemen.

Ed Cohen

Hey John.

John Ragozzino - RBC Capital Markets

Mark you provided some color on the fourth quarter ‘13 impact from the weather and forgive if I missed this but it seems quite a little bit more color on what the 2014 first quarter impact might be in terms of production volumes or cash flows in fact in the weather?

Mark Biderman

Yes John, at this point, we’re still trying to quantify the storms in February had, storms in early February we had a bigger impact in February had, it’s quite impact really in January, early February was the biggest impact, we’re really with the end of February we’re still kind of quantifying and point then together. So we’re going through that process and times to make sure that we get the most accurate numbers in terms of I thought.

I normally have anything to provide you right at this point in time. But we’re going to be actively working throughout on both, accounting and financing will be operational teams would be really works that, I think Matt team and that he can talk about this has really done a great job, bring those volumes back in line as quickly as possible given all the problems we had during the period.

John Ragozzino - RBC Capital Markets

Great, and just by giving up some interim update when you do kind of (inaudible) number?

Sean McGrath

We haven’t talked about that yet I mean, if we had something that at a point in time, before the first quarter earnings call, we will definitely discuss that and term whether we wanted to put that out there ahead of time.

John Ragozzino - RBC Capital Markets

Okay, great. And then Mark, you guys mentioned your partnership with SandRidge in the Mississippi Lime, yesterday they gave a brief update or brief bump to their type curve assumption and their EUR is about 380 MBoe. Can you discuss what their, what the difference is if any are between your assumptions of how the Mississippian wells perform over the long-term and what SandRidge is?

Mark Biderman

The SandRidge company has an acreage position that traversing across something like 1.7 million acreage that generates at the volume of the Mississippi Lime play. I would suggest their acreage is in what I believe SandRidge would also characterize is the core, if not the core is in, the core of the core of the play. And so as far as EUR consumptions are concerned to a degree and when we first get started it’s to continue through today has started in our development of Mississippi Lime play. We leaned on type curves that SandRidge was using, what we have found and we haven’t change by the way our type group assumption which is on or about actually a little bit lower than the number that you just mentioned. The SandRidge is now using, but what we are experiencing in higher production than the type curve would suggest. So I hope certainly that will continue which will lead us also to bump up our type curve assumption in future periods.

John Ragozzino - RBC Capital Markets

And just as a follow up to that question. Over the last couple of years, they have had some real trouble with getting and good handle for the different products streams and the associated decline rates and then best possible number of revisions. Have you seen anything that I guess the materially different from your expectations when it comes to oil decline rate relative to how fast gas volumes decline or is it something that you have been aware of?

Sean McGrath

It’s not something that we have necessarily seen in our properties and our production. And I would really not speculate on what SandRidge has experienced and where they have had their experiences, but my speculation is that one of the reasons that SandRidge hold back to their core areas was because they were getting probably getting better production in the core area compared to some the trends areas they were testing and they have been experiencing higher gas component as compared to liquid component potentially higher decline. I don’t know that for a fact that speculations but that maybe the case.

John Ragozzino - RBC Capital Markets

I will move on. I don’t want to pick on them for anything in specific. Ed just one more on the partnership program. You guys mentioned the target of about $200 million in 2014. I mean huge (inaudible) program once that finally come out, and I'm understanding all the benefits that it can better provide to you guys.

But allow me to (inaudible) if there was expected demand beyond that $200 million for 2013, is there a potential risk that the portfolio decline rate may experience some undesired inflationary pressure driven by excessive wells drilled in place such as the Mississippian.

Ed Cohen

I would say that the $200 million figure is the figure that we budgeted. It's not a target figure in the sense that we hope to reach that point. We actually have registered a program that could go to $300 million and I would not be surprised if we reach that number given the response to last year's program and other factors. We can easily handle the $300 million.

John Ragozzino - RBC Capital Markets

Okay, I guess let me just revert the questions just slightly. If you did have effective demand beyond $200 million and that had the opportunity to deploy significant capital above that in those plays. Would you chose to do so or would you need your activities levels at kind a where you have budgeted them at the risk of maintaining a portfolio decline rate that's more manageable.

Ed Cohen

I don’t think the portfolio decline rate is a factor in the partnership program. I think that we're simply being conservative in budgeting the $200 million. We find that people are pleased if we do $300 million where we have budgeted $200 million and on the other hand I mean obviously if we are not conservative and I do not think this is conservative.

Sean McGrath

And if I could just add from an operating point of view, we always build in optionality. So that we're prepared to the deploying capital in the various regions where we operate. So we have a plan in place to deploy more capital that a conservative $200 million number would suggest. So we’re prepared to deploy more capital if that circumstances evolve.

Matt Jones

John, I would also mention that when we look at our overall growth strategy drilling a bunch of programs are one half of that or two thirds of it. We also look to grow through acquisition acquiring low-decline PDP oriented properties. So the combination of the two as we continue to grow that drilling programs the one third that we have and as well as direct drilling becomes a smaller percentage of the overall growth. So you’re growing like an EP acquisition which has an 8% to 10% decline and you’re adding wells, you have a third interesting with the partnership programs that have the declines and profile associated with them. The overall decline in portfolio that isn’t going to be as impacted by raising an additional $50 million to $100 million of partnership program.

John Ragozzino - RBC Capital Markets

That’s exactly what I was looking for. Thank you very much. And just two real quick housekeeping ones. When do you expect to file the K? And is there any plan in place within the next 12 months to possibly hold some Analyst Day or event that would give us a little bit more of an opportunity to come take the (inaudible) a little bit?

Sean McGrath

John as we do on a regular fashion we’ll have group meeting with investors. Now definitive plans for a larger Investor Day at this point. So I thought that what we consider for the future, obviously with our attendance in a lot of meetings and conferences over the course of the year we have a lot of exposure and ample opportunity to update our planning for rest of the year.

Brian Begley

Yes. And the K should be filed in the next couple of hours.

John Ragozzino - RBC Capital Markets

Fantastic. Thanks a lot guys.

Ed Cohen

Thanks John.

Sean McGrath

Thanks John.

Operator

(Operator Instructions). And our next question comes from the line of Craig Shere with Tuohy Brothers. Please proceed.

Craig Shere - Tuohy Brothers

Good morning guys.

Ed Cohen

Hi, Craig.

Craig Shere - Tuohy Brothers

Congratulations on a good quarter. So let me just take you back on John’s question around the partnership raise. The increase was certainly helpful year-over-year, but perhaps a little anti climactic given the fact that last year was down from the stub of the prior year and in this period we had rising gas prices and to the end of the year that obviously accelerated their clarity around rising interest rates. And you had some good 2013 drilling results. So as we think about potentially doing better than the $200 million budgeted capital raise for this year. What do you think the obstacles were previously and what could get us over the hump because I know you have done twice that historically some years ago?

Ed Cohen

That’s an excellent point Craig, this is Ed. Prior to the Chevron sale we consistently raised without great effort, without great pressure $350 million to $450 million. The Chevron sales eliminated our abilities to immediately provide an acreage of course we do now with the new company we had very limited add backs. So I think that the disappointment that investors had when we perhaps equally.

So figured using other joint venture partners we assume that they might not do as well as Atlas but they would do okay. That was the disappointment to us and for the investors. Now for the first time, investors are getting the result, very favorable result of Atlas’ done programs and I think that goal takes us over the hub. That’s why I considered $200 million to be conservative expectation. And I think that in the future there is no reason why we would not get back to any (inaudible) what we did previously.

Craig Shere - Tuohy Brothers

That would be great to see and that's what big part of story, so we’ll keep an eye on that. Also a little surprised about maintaining reduced distribution guidance from last October in light of, to Sean’s point, that’s rising commodity price tailwind that obviously is helping at least first quarter ‘14. Can you discuss your price take assumptions for the rest of the year versus current market, your basis fair assumptions and what your distribution policy is, this relates to these kind of commodity driven fluctuations or windfall if you will?

Ed Cohen

Craig, this is Ed. Before Sean’s answers it I wanted to emphasize again that this is a static projection. It doesn’t assume any value to many programs and efforts that we’re undertaking, that we’ll unfold during the year 2014. That being said, Sean why don’t you answer directly?

Sean McGrath

Sure. Craig yes absolutely. When we look at 2014, I mean just remember that for gas we’re hedged over 80%, probably 80%, 85% same with oil, both were pretty solid prices. On the NGL side, when you look at the heaviers we’re probably 55% plus hedged and propane were probably in the I would say, 75% hedge range. So we are hedged at very good prices for 2014.

So while the uplift in prices is helpful to an extent, it’s -- we are heavily protected already at good price. So, this helps us with our unhedged volumes, so we will see a certain impact to that, but not where the original prices were going back, prior to middle of the 2013. So, we expect and hopefully and stay there. We’re going to look for good opportunities to lock in those prices. But we have already protected ourselves against the potential downside movements, so.

Craig Shere - Tuohy Brothers

Okay, fair enough. And this might be a good opportunity to dovetail this questioning with some of the prior questioning. I think it was Noel’s comments about commodity prices and the opportunities start developing some of the gassier areas. And I think Matt commented on the Barnett. One of the things though is, we are seeing short term movements, I mean turbocharged, but the 2015 and 2016 and beyond strips haven’t moved that much. And if you’re going to think about a drilling program, a multi-year program, you obviously, obviously historically have shown that you want to hedge out your turns and improve that you have some level of locked in cash flow and distributions for investors. What do you need to see, I guess this is directed more to Matt, what do you need to see in terms of longer term strips and the ability to hedge before you start taking a look at seriously returning to dry gas drilling?

Matt Jones

Well, the first thing we need to see, Craig is the -- we’ll undertake the analysis and we will allocate capital according to what we believe will be the highest returning projects that we have. And so for the gas projects, the dry gas projects except -- with the exception probably of our Lycoming project, which is unique and the ability to generate volume per dollar of investment. For the other gas project, they’re simply, for our capital allocation internally, they’re simply going to have to be competitive with the more oily and liquid, liquidy oriented locations.

So, when that occurs with the crossover point will be based on a variety of dynamics including natural gas prices currently, including natural gas prices on a forward strip. That relative to oil prices and NGL prices will all be part of the arithmetic review that we’ll undertake and which is ongoing.

I think my personal opinion is in and I think that we generally share this in our company is that the forward curve for -- first of all obviously the natural gas curve today is recognizing that in order to refill storage levels, producers are going to have to be induced by price to drill -- to refill storage levels. I think beyond say the first early into the second quarter of next year, the forward curve is [backward aided]. And I think that that will probably prove to be inaccurate that forward prices after the first quarter of next year are likely, I believe to increase through time.

We are not going to allocate capital based on that presumption or that belief. But if we see that happen, I think we will and if we see that happen and then we see gas prices advance to the point that it substantiates allocating capital to dry gas locations and to oily locations, we’ll certainly do that.

Craig Shere - Tuohy Brothers

Matt, I really appreciate that because I share that view of the gas markets. But let me expand a little on the question because your response kind of assumed constraints and limits in the capital budget where you have to make choices and we all have to make choices in life. But let’s just imagine for the moment that you do have a significantly better private partnership raise in the next or this year and that you don’t have significant capital constraints. If you’re thinking about garnering 20%, 30% IRRs, at what level do you need to be able to hedge out long-term strips to start to drilling the Barnett and the gas [results]?

Matt Jones

Well I think the Barnett in particular I think gas prices that are in the $4 range and that potentially moving to a [continual] position from their causes the Barnett to be economic whether the Barnett becomes economic at those levels, competitively economic with some of other opportunities is something we have to evaluate if and when that condition prevails. I think the part of the ability -- if we had more capital in an infinite capital available world, we probably choose to ramp up activity in the areas that today are providing the greatest returns and then I get back to the areas where we’re drilling: Mississippi Lime, the oil Marble Falls, the high returning dry gas areas in the Marcellus et cetera those areas where we’re really focusing our capital.

Craig Shere - Tuohy Brothers

Okay.

Ed Cohen

This is Ed, Craig. I think you should bear in mind that there are many factors in the energy industry who are not as conservative as we are. We’ve always liked the idea of hedging for immediate profitability but it’s obvious that there are a lot of people who believe that the futures markets since the effort to drive major banks out of playing the role in the commodities markets that they’ve played in the past when they were able trade for their own account, a lot of people believe that the markets no longer reflect the considered judgment of the world as to where prices will be in the future and a lot of people like us have a different view as to whether the futures market really should be backward dated. Those persons may will desire to purchase our acreage and that’s another element that may take place.

Craig Shere - Tuohy Brothers

Thanks that’s an excellent point. And well I have got to my last question really for the AGP if you are able to answer and thank you so much for the additional color in your prepared comments. My question is you said you raised the fund raising amount you are not anywhere close to original $300 million at this point, are you?

Ed Cohen

I don’t want to go there because the one thing we can’t comment on is the fund raising aspect I know it bother people during the period that we were doing the tax oriented fund raising that we could not comment, but we simply can’t talk about that.

Craig Shere - Tuohy Brothers

Understood. Thanks again for all the answer. Thank you.

Ed Cohen

Thanks Craig.

Operator

And our next question comes from the line of Sean Sneeden with Oppenheimer. Please proceed.

Sean Sneeden - Oppenheimer

Hi, good morning. Thank you for taking the question.

Ed Cohen

Hey Sean no problem.

Sean Sneeden - Oppenheimer

Ed or Sean, could you maybe talk a little bit more about the M&A environment that you guys are seeing out there in kind of broad stroke do you feel there are more of the deals out there or are you guys more focused on the GeoMet type of transactions that was first year?

Ed Cohen

I think those deals basically differ in size. The motivations also differ based on somebody’s particular corporate situation if an acquisition has been made and you are dispersing, they disposing some of the properties. But the overall market I think is really strong; there are lots of lots of GeoMet type deals available. Obviously there are fewer deals in the larger size, but those deals are present. I think that the smaller deals are of less interest to larger companies and therefore you don’t get the hectic price competition that you get in the other areas. But we have lots of opportunities, we will look at each particular situation and really it was best for the company.

But a failure to complete a deal will not reflect the fact that there aren’t lots of opportunities. Daniel Herz, is he still on the call?

Daniel Herz

Yes I am Ed.

Ed Cohen

Yes. Daniel head our effort in this area as in some other areas. So Daniel do you want to comment?

Daniel Herz

No I think your comments are exactly right, the M&A environment is robust today, both for smaller opportunities, as well as larger opportunities. There are lot of ENT companies that are divesting of asset that we would, we find very attractive to redeploy that capital elsewhere. And similar to other transactions we've done in the past, there are private equity firms that are winding up their investment wise and looking to divest of those assets.

Sean Sneeden - Oppenheimer

Well, that's helpful. Maybe in terms of hunting about this right you are probably on the margin than your preferences first on this far, you feel this more value and less your price competition, is that fair assumption?

Ed Cohen

We do lean in that direction, but every time you start leaning in that direction you are amazed, I am talking from a past, when suddenly a fantastic deal comes along that’s properly priced often for reasons that we could not have anticipated. And so the past with any guide for future, it’s hard to predict that just we will wind up, but it’s really nice to know that there are some opportunities.

Sean Sneeden - Oppenheimer

Fair enough, fair enough. And then Sean, I apologize if you already gave this, but could you maybe remind us how we should be thinking about unit production cost this year, is it roughly similar to the fourth quarter?

Sean McGrath

I am sorry, unit, like LOE and crash cost per unit, yes, that’s right. Well, I think overall even if you look at 2014, its probably in the $1.05 to $1.15 area before it depends on the timing of level of oils production, the liquids production that we are coming on obviously as liquids productions increases its going to raise that number up because you are using even through more valuable units, fewer units to spread the cost around.

Sean Sneeden - Oppenheimer

Okay. I appreciate that. And then just one last quick one, maybe for Matt, do you think I hear Miss Lime acreage perspective for additional zone, you have SandRidge to talk about the chapter and some of their zones (inaudible) any this year?

Matt Jones

That’s an excellent question and I had given some broad dimentioning today that there are particular SandRidge has announced that they are gravitating towards this service stack pay approach, if you will drilling other units, and we are watching doing.

It has merit we believe because you might recall our -- Mississippi Lime is particularly, I think where we operate. So we think they're probably our opportunities to drill in or the unit between the shallow section of the formation deeper sections of the formation.

The other thing is interesting is that kind of offsetting clanking our property sort of the east to where we're located. There have been very attractive Woodford Shale wells drilled. So we're watching that closely. In terms of our capital plan for 2014. We are not allocating capital to either intermediate stack pay approach if you will or the Woodford. We are very, very closely watching and our what's occurring around us and pretty excited about and we'll see it occurs. But no, we're not allocating capital in that direction yet.

Sean Sneeden - Oppenheimer

Okay. And I appreciate that, that's helpful. Thank you guys.

Sean McGrath

Sure. Thank you.

Operator

At this time, there are no further questions in the queue. I would like to turn the call back to Ed Cohen for any closing comments.

Ed Cohen

Hi, thanks everyone for their participation. We look forward to the next call. Bye. bye.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may all disconnect. Good day everyone.

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