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

Q4 2013 Earnings Conference Call

February 28, 2014 9:00 AM ET

Executives

Brian Begley – VP, IR

Edward Cohen- Chairman and CEO

Matthew Jones – President

Sean McGrath – CFO

Mark Schumacher – COO

Analysts

Noel Parks – Ladenburg Thalmann

Michael Gaiden – Robert W. Baird

John Ragozzino – RBC Capital Markets

Operator

Good day, ladies and gentleman, and welcome to the Fourth Quarter Atlas Energy L.P. and Atlas Resource Partners L.P. Fourth Quarter Earnings Conference Call. My name is Lacey, 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 get 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 address our expected future business and financial performance, and financial condition 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 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.

In both, our Atlas Energy and Atlas Resource earnings releases, we provide a GAAP reconciliation of the non-GAAP measures that we refer to in our public disclosures. I’d also like to note that as of today, Atlas Resource Partners 2013 K-1 tax forms are now available on our website atlasresourcepartners.com, and the Atlas Energy K-1 forms will be online at atlasenergy.com next Friday, March 7.

Lastly, we’ll be participating in several upcoming investor conferences, including the Morgan Stanley Corporate Access Event in New York on next Tuesday, March 4; the Capital Link MLP Form, next Thursday in New York, March 6; and the ICAA New York Conference on Monday, April 4.

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

Edward 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, it’s doing no benefit from fresh initiatives such as the extensive reworking of wells that we’re undertaking, or from acquisitions or from now unscheduled expansions that may position our company to improve results in 2014, and for even greater success in 2015.

Now, let me see tangibly. I’m 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 returns for unitholders for 2013 was about 39%, and ATLS’s total return of 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 our highest returns in the entire world energy industry for that period.

But of course, I’m also unhappy about the performance of Atlas Pipeline Partners, APL, which is down about 12% during the past three months, that’s a decrease that has comparing 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 quite solid, but the reality is just the buy I think, optimistic expectations for the near and further future. Both intangible accomplishment, and in returns for unitholder. Let me speak first briefly about APL, and then in length about ARP and ATLS.

APL stock price has been fumbled by investor disappointment over APL’s failure immediately took out new Silver Oak plant, south Texas, and by lackluster results at its Arkoma division in south Oklahoma. These are, in my opinion, trenching difficulties of the past that should not be 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 Diego/Ford basins in Texas, and then SCOOP and Mississippi Lime areas in Oklahoma. In APL’s quarterly call last Tuesday, pipeline management explained how these operational difficulties were being solved. How Silver Oak I was being filled, and how the new pipeline connection between APL’s Velma and Arkoma’s facilities will show our plan hands 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 bulging natural gas intake which shortly if exhausted Velma’s process capacity.

But the bigger picture at APL should not be ignored. In the Permian basin in West Texas, which today with the Shell revolution is perhaps the world’s fastest growing energy producing area, and already perhaps the second most prolific player 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 per day processing plant every 18 months, and that just to keep up with the customers bulging production. Now that pace may actually accelerate but the speed up is likely to continue for years since the future. Every new Permian plant filled needs about $65 million, and additional EBITDA per year per plant. That’s a 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, that’s $180 million per plant.

In the Eagle Ford in southern Texas, is running the Permian close race to the growth. It’s hard for me to believe that APL speed investment of $1 billion in 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 provide the basis for great results in APL’s South Oklahoma division. And the Mississippi Lime is similarly burgeoning in Western Oklahoma were volumes in the fourth quarter were 538 million cubic feet per day, an outstanding 23% increase over the fourth quarter of 2012. And now incomparable of at the former CEO’s of Jestafe [ph] and SandRidge through their new fund are reported to be in a process of investing yet more $1 billion in the Mississippi Lime areas of Oklahoma and adjoining states augmenting a huge investment programs of their former companies and other, and auguring the possibility of even more growth and even more profit for APL, and presumably more incentive, that is, IBR income for ATLS as general partner.

Now, the Mississippi Lime of course, is where Atlas Resource Partners, ARP, continues the yield strong levels of oil and liquids production. There, and in the Marble Falls, the Utica, and the Marcellus; added resource – the Atlas Resource Partners has achieved increasingly favorable results. For example, the three-fold increase year-over-year in high margin oil production, items which ARP CEO, Matt Jones, will shortly discuss in detail. In fact, ARP 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 that’s generated from the bid and from successful acquisitions, the important Raton and Black Warrior assets acquired a little over a year ago have performed even better than our projections. ARP has now increased quarterly distribution with $0.58 per limited partner units 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 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. It was $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 14, ARP announced that it has agreed to acquire approximately 70 billion cubic feet equivalents of proved reserves of natural gas in West Virginia and Virginia from GeoMet for $107 million, with an effective date of January 1, 2014. The transaction is subject to customary conditions including approval from GeoMet’s stockholders, with the company’s largest shareholders legally obligated already for the transaction. This mature, low-decline production is expected to be immediately accretive to ARP distributable cash flow per unit. Current net production from the assets is approximately 22 million cubic feet equivalents per day from over 400 active wells, with a current expected annual decline rate of approximately 10% to 12%. The GeoMet acquisition is thus highly compatible with ARP’s policy of operating Long Lived, Low Decline Reserve, a policy that had already been enormously advanced on July 31, 2013, by the much larger acquisitions from EP Energy of some 3,000 seasoned producing well, principally in the Raton Basin in northern New Mexico, and the Black Warrior Basin in Alabama.

EP acquisition substantially reduced our annual decline rates, thus effectively minimizing future expenditures required to maintain revenue, so far maintenance CapEx. Now we anticipate the addition of the GeoMet asset will further consolidate ARP’s already low rate of decline on producing assets. I should also elude 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 reduced programs, helped ARP to maintain an elevated level of expertise and experience in various aspects of the EP business, and that’s mutually as 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 their work. We have now increased the size of the offering from its original $300 billion to $500 billion. Atlas Growth now has committed rig running on its acreage in the Marble Falls area with three wells producing already, two more wells drilled and completed and currently cleaning up through flow back. The further well now drills the total debt and an additional well currently in the process of being drilled. Initial distribution at a 7% annualized rate have been paid through initial unitholder.

ARP has also introduced its new monthly distribution policy. The clearing in initial distribution of $19.75 [ph] per common unit for the month of January 2014. The monthly distribution policy which is more demanding of ARP’s back office has listed it a favorable response from unitholder.

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, a company newly admitted to trading on the New York Stock Exchange under the symbol ARCX. ATLS has declared a cash distribution of $0.46 per limited partner unit for the 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 ARS [ph], ATLS now expects distribution to unitholders in 2014 to grow to a range of $1.95 to $1.45 per common unit. This represent 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.

Matthew Jones

Thank you, Ed and thank you all for joining our call. The fourth quarter of 2013 concludes 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 three-fold increase in high margin oil production. Not only have we greatly increased our production but we also have significantly diversified across basins and regions, and materially lowered our portfolio decline rate bringing out stability to our production stream. The total production increase was a key factor and our peer leading cash distribution growth rate of 21% for the fourth quarter of 2013 compared to the fourth quarter of 2012, so that’s behind the numbers.

Our track record results from both acquisition and organic growth, including the effective acquisition and assimilation of high quality producing assets, the exploitation of liquids rich and high yielding dry gas drilling 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 focused business plan, and develop and manage our attractive assets compared to any other time in our history. We’re better positioned to expand areas of our business for the preferred well, and to address the areas where we believe we can improve. Key of that belief is an all important element that I have a benefit of witnessing every day, and that is the collective experience, talent and dedication of our teams [ph]. This important element manifests in many of the exciting aspects of our business that I’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 battled through incredibly harsh winter weather conditions that the region has had, to keep our wells flowing and our well drilling completions operations functioning as fast as humanly possible. Our fourth quarter results would have been even better not for this obvious and uncontrollable factor, and our first quarter production will be impacted as well. However, with extreme weather conditions recently evading, our production results are moving higher, and we expect continued progress for the remainder of the quarter.

Our multi-level growth approach continued to progress on all fronts. Our recently announced definitive agreement to acquire approximately 70 Bcfe of low decline proved developed producing natural gas wells from GeoMet further diversifies our production stream, it fits very efficiently into our Coalbed Methane segment where we’ll lever our company’s core knowledge of CBM assets. The assets also include 30 or more potential drilling locations all held by production from a lot of these locations to our wide and varied list of future drilling options available within our asset base. We also anticipate bringing on-board the GeoMet’s field operations team, this is the team that has worked these assets for many years, and we look forward to welcome them into Atlas.

The GeoMet’s CBM asset acquisition follows our highly successful acquisition of CBM assets and the Raton and Black Warrior Basins from EP Energy last year. The low decline asset acquired from EP continued to perform at or above our acquisition expectations, and our CBM asset team is focused on bringing forward economically efficient ways 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 arresting already low decline rates and providing very competitive returns compared to other projects. We believe that the compression project will have a payback period of less than nine months with anticipated increased production coming from oils and infrastructure that are already in place.

As pleased is we are over the performance of our recent acquisitions, we’re 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. The entire belief that our focus on exploiting liquid enhanced drilling location allows us to efficiently replace natural declines in our producing assets to provide an attractive core drilling prospect for our company and for those who invest in our drilling program offering. From our Mississippi Lime position, we connected four wells in the fourth quarter, all in the month of December. So we now have 60 days of production in each of the well. On average over the 60-day period, the wells connected in the fourth quarter produced 484 BOE per day, materially exceeding our tight group for this period of 283 BOE per day.

Of equal importance, the composition of the production is roughly 50%, liquids also exceeding our tight curve with a 125 barrels of oil, and 115 barrels of NGLs produced on average per production day. While the results from these wells alone would be exciting and encouraging, what is perhaps more significant is the trend that is developing with our Mississippi Lime performance. Some of the colors today may remember that we reported the connection of five wells in our Mississippi Lime program in the third quarter of 2013 with initial production rates meaningfully exceeding tight curve assumptions, these wells today 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 plant.

Key investment include improved understanding of horizontal landing target, maintaining oil boards within target zones throughout the lateral, and more efficient, better completion techniques. It also lowered our drilling and completion cost further improving our capital efficiency in the plant. Our well cost now generally range from $3.6 million to $4.5 million per well, with a range of reflecting the varying costs associated with drilling for the shallow versus deeper section of the formation. All of our well drilling activities in the Miss Lime in the third and fourth quarter of 2013 and continuing into the first quarter of 2014 is being funded to our 2013 Series 33 Direct Investment Program. Important to note, that ARP owns an approximate 33% interest in the Series 33 program, so we are 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 two rigs running dedicated to the completion of wells in our Series 33 program. For the end of the second quarter of 2014 we’ll finish the Series 33 wells, drilling additional salt water disposal well, and initiate drilling of several Miss Lime wells for our company’s direct interest. We also plan to initiate Miss Lime drilling associated with our 2014 Series 34 Direct Investment Program late in the second quarter and continue 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 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 a 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 County, and is offset on several fronts by SandRidge disposition.

Lastly, from a field operations point of view, our Miss Lime asset team is highly focused on optimizing water takeaway, a disposable methods, methods in electrical grid capacity to maximize – to minimize downtime. Maximizing utilization of our existing infrastructure and targeting extension 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 and Lycoming County, Pennsylvania last year, and drilling completed 8 horizontal wells that we brought online in the third quarter. I’m pleased to report that in the first 180 days of production, the wells have produced an accessible 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 continue to produce around 6 million a day per well on average. Totally UR designed for 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 or in close 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 from Marcellus produces recently has been the volatile basis differentials caused by limited pipeline capacity. Limited capacity presents an opportunity for mid-stream developers and substantial additional capacities planned which should relief bottlenecks in future period.

In Lycoming, we were priced off providing index. Over the last 10 day prices have ranged $4 and $5.20, in fact today, we understand while pricing is around $4.44, compared to spot and the up prices today is about $4.53. The pricing was average $4, the low-end of the range, IR Arizona [ph] identified drilling locations would likely exceed 30% or more. Even if prices average $3.25 which represents average –- pricing from November 1 to November 27, our Lycoming drilling prospects generated 15% to 20% returns. These expected outcomes reflect a lower finding and development cost, and low operating costs 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 Country, Ohio, where we built a single-pad location, it was engineered to accommodate five horizontal Utica wells and the wet gas window. Following site development, drilling and completion, we brought the five wells online in September of last year. Nearly and currently, a key processing plant raising crossfire and was taken out of service early January of this year. Because of the restricted processing capacity, and because their wells had greater proportion of high rate condensate than we had original anticipated, we’d blow the wells more slowly than original contemplated which has led to steadier state of production as compared to high initial reduction rates.

Cumulatively in the first 136 days of production, we produced roughly 87,000 barrels of high-grade condensate from the wells, 17,000 barrels of NGLs, and 330 million cubic feet of residue gas. Even after the first four months of production, the wells continue to produce in a range of 400 to 500 barrels of condensate per day and we anticipate low decline rates moving forward.

Currently in the Utica play, we’ve drilled, now nearly finished the completion of 51 back [ph] stages on three wells drilled from a single patch site on our Columbiana County property where we have roughly 1200 continuous acres under leaks. All operations have proceeded according to plan. The relative average lateral lengths of about 5,400 feet, the wells are being funded through our Series 33 direct investment program, we anticipate initial production from the wells in early June of this year, and we’ll provide updates accordingly as the year progresses. Also worth noting, Tatal [ph] is investing in these wells as non-op participant.

Lastly, because of these agitated [ph] 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 individually have lateral lengths in access of 5,000 feet.

Moving to our Texas operations, we continue to develop our oily Marble Falls asset, where our vertical drilling program allows us to complete multiple zones and seek stack pay opportunities including the Marble Falls, Barnett Shale, Bend conglomerates, the Caddo, and Chappel Reefs. The recent successful wells include wells where we’ve produced only from the Marble Falls, the wells that benefit from stack pay completion. Our best performing wells to-date and 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.

The intervention 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 models for drilling activities partially funded through our Series 33 drilling investment program and partially from ARP’s cash resources. The two rigs running in the Marble Falls from the fourth quarter we spotted 22 gross wells and 11 net wells, and in the first quarter 2014 we’re scheduled to spot 24 gross and 12 net wells. It’s important to note that the Marble Falls region was the hardest hit among our areas of operations by the November through February weather anomaly. High storms and well freeze [ph] 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 well site.

Having adored that experience, our Marble Falls team is happy to report the production levels are rebounding, and wells completed during this period appeared to be within expected ranges. We should have more data to share on our next earnings call.

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 vast majority of the wells are scheduled for inclusion in the remainder of our 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 for incompletion opportunities in the greater Marble Falls play. This is composed largely of various bypass behind Pipe A [ph] of the Bend conglomerates and Marble Falls sections.

Lastly, we announced SEC based year-end 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 acquisitions of producing natural gas assets in the Raton and Black Warrior Basin. Offsetting these additions, was the removal of 34 Barnett Shale PUD location totaling 79 Bcfe approved undeveloped reserves, primarily associated with the SEC five-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 looking after [ph] the financial review.

Sean McGrath

Thank you, Matt, and thanks 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 were unfavorably impacted by approximately $2.5 million to $3 million due to lower volumes on 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 on these results, representing approximately 1.5 – 1.05 times coverage ratio for the quarter adding back restored impact at 1.1 times coverage ratio on a rolling four quarter basis.

Adding back the impact from 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 overall 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’s third quarter production run rate of approximately 261 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 basis differentials at a number of our sales point. Pricing for our Lycoming gas at Leidy Hub [ph] which count for approximately 8% of our total natural gas production, averaged almost $2.85 per Mcf for the current period compared to $2.15 per Mcf for the third quarter of 2013, an improvement of over 30% from the sequential quarter, although it’s still reflected – still reflected a 20% differential from Henry Hub, first month pricing of $3.50 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 draws, not seen in recent years. Henry Hub first two month price for the first quarter of 2014 was [ph] almost $5 per Mmb, including the February contract selling at almost $5.60 per Mc. While our natural gas production is hedged to a great extent for the first quarter 2014, ARP still has 35 million cubic feet to 40 million cubic feet of natural gas a day which is sold at daily prices. That should boost our results for the first quarter. For example, our Barnett and Marble Falls gas have witnessed average daily prices of almost $6 per Mcf for the first two months of 2014, with certain days spiking to over $20 per Mcf.

With regards to liquids, oil prices also stayed strong for the fourth quarter. As WTI prices averaged almost $94 per barrel. In addition, NGL prices, strictly 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 $1.2 per gallon for the sequential quarter, an 18% increase, and have remained strong for the first two months of 2014. I think prices also, both seen an uplift during the first few months of 2014. As 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 Utica Shale during the third quarter.

I’d like to mention that we have Adjusted Bcf, 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 on last quarter’s call. For 2014, our guidance [indiscernible] at least to enter partnership investor funds, a 33% increase from 2013, and deploys approximately $180 million of investors capital for running a significant 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 was almost $2 million lower than the third quarter of 2013, which was due to $2.5 million increase in the capitalization of administrative cost associated with ARP’s 2013 partnership program, due to an increase in funds raised from the sequential quarter. ARP capitalized to certain amounts of its G&A costs 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 $42 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 Lime region, and $17 million of investments in our partnership programs. For 2014, we anticipated ARP’s total capital expenditures to be between $185 million and $200 million, including the $150 million to $160 million for work over and well joint activity, including $75 million to $80 million of drilling directly to ARP’s account.

With regard to maintenance capital expenditure, in a manner, and by multiplying our forecasted future full year production margin by our expected arrears production decline of PDP wells, which is current forecasted to being – also expect to drill that will generate an estimated first year margin, equivalent to that production margin decline. [Indiscernible].

We provided additional details with regard to assumptions utilized in 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 an average of approximately 100% of our current run rate crude oil production through 2015 at an effective average floor price of approximately $90 per barrel with additional hedges through 2017.

As a reminder, 100% of our commodity derivatives are swaps and collars, which simply provide us protection against commodity price movements. We are committed to continue to add protection to our business by providing 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 table’s within our press release for more information about our hedges. Although it is a non-cash item, I wanted to note that we recognize $38 million of gas and oil property impairment at our non-core New Albany and Chattanooga Shale region. These impairments consisted of approximately $40 million of expected under our [ph] lease explorations in the coming years in New Albany and Chattanooga regions, as well as the $24 million impairment of our New Albany oil and gas property.

With regards to New Albany oil and gas property impairment, our current near term non gas prices are at/or higher than comparable prior year prices. The price set for 2018 which is required by accounting regulation to calculate their value for the majority of production from this region at December 31 was more than 10% lower than the prior year. We do not expect to have any additional oil and gas property impairments at future period assuming current commodity price.

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 a leverage ratio of approximately 4 times. I’d like to point out that if you recognize $47 million of subscriptions receivable on its balance sheet at year-end which reflects contribution to its partnership program as of year-end for which ARP’s did not recognize the cash on 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 entering 2014 with a leverage ratio of below 3.5 times and with a long-term target below the 3 times level.

In closing for ARP, I’d like to mention that with regard to our guidance for 2014, we anticipate a ramp on ARP’s Adjusted EBITDA, and Bcf during the course of the year due to the timing of partnership margin recognition and well connection for our developmental activity. For the first quarter of 2014, we anticipate Adjusted EBITDA, Bcf, and cash distributions per unit to be quite similar to the fourth quarter of 2013 excluding the impact on production volumes and margins from the storms and severe weather ARP and others have experienced in the first two months of the year.

With regard to Atlas Energy LP, we generated distributable cash flow of almost $24 million and distributed $0.46 per unit for the period, representing a coverage ratio of one times. 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 ATLS to continue to maintain minimum coverage on its cash distribution on a reported basis. Atlas Energy recognized over $9.5 million of 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 $70 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 a $150 from the prior year fourth quarter of 2013.

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 cash G&A expense is generally higher than the first half of the calendar year through the seasonal expenses including Annual Shareholder Meeting and a compliance costs.

Finally, I would like to quickly mention, ATLS’s strong standalone balance sheet at year-end which is $17 million of cash and an undrawn $50 million of credit facility, along with leverage of 2.5 times.

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

Edward Cohen

Thanks, Matt. Thanks, Sean. I think we’ve given you a lot to digest but we will now – Lacey 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.

Edward Cohen

Good morning.

Matthew Jones

Good morning.

Noel Parks – Ladenburg Thalmann

Just a couple of things. Thinking about just overall with your portfolio as a key to broaden over the last year in particular, where do you see the – I guess, the most mismatch or gap in terms of the regions where you probably still need technical manpower, the most – sort of, overstaffed or, versus understaffed regions. Just wondering what your biggest challenge is regionally as far as Black Warrior [ph]?

Edward Cohen

Matt?

Matthew 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’re undertaking, overseeing the operations, field management operations, making sure that we’re ahead of schedule in terms of ops, improving water systems, drilling salt water disposal capacity and 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 Lime, and the Marble Falls areas. We benefited in both of those areas for having people who have experience in both, north Texas and the Barnett Shale and the Marble Falls, and in the Mississippi Lime, or broadly speaking, our company today has people who are very well experienced in all regions where we’re 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 in some areas and with producing assets that we’ve acquired. But, 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 activities and undertaking those primary areas.

Noel Parks – Ladenburg Thalmann

Okay. And, since we’ve – with the cold winter we’ve seen some whopping improvement in the spot and also this trick. Now which of the major reasons of your gas production – which one has benefited the most from say, I don’t know, maybe a year ago we were thinking about – I don’t know, a $3.50 to $4 strip as being maybe what we – what we have to assess a little while and now for your – we’re looking $4.50 range. That incremental difference, which region has helped the most?

Matthew Jones

You have to bear in mind that we are heavily hedged to that extent but Sean, were you about to respond?

Sean McGrath

Yes, I was trying to correlate, did you mean drilling opportunities, which really – regions that helped with them with drilling opportunities to drill wells because more wells are economical or did you mean just what – where we’re going most up in terms of pricing per region?

Noel Parks – Ladenburg Thalmann

I think I meant just in terms of economics, you know, some password is of course they – the $3.50 gas and explore gas is a big inflection point and then other is, when you get – when you cannot be optimist took a better than forth, you know that really helps to bring them from just breakeven to much better economic.

Matthew Jones

Noel, I think that the one area that we have, that will likely benefit more than any other, from higher – potentially higher, realized higher than natural gas price, they have potential prices going forward. These are Barnett Shale position, we have a fair number, quite a few drilling locations in the Barnett Shale, particularly the dry gas windows Barnett Shale where we have drilling sites that are available to us on – add sites that have been developed or infrastructure is in place where we have frankly the greatest – to 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, the cost is said to be – those assets being competitive with the other areas we’re drilling.

But the Barnett Shale will clearly benefit from our natural gas prices. We have quite a few locations in the Raton are and the Black Warrior basin area, that will benefit from higher natural gas prices as well. And as the Lycoming assets are – that we have, they will also benefit from higher prices. So we have quite a few drilling locations where we have embedded infrastructure, takeaway capacities in place. Infrastructure has been built, PAD locations are developed, with benefits that are available to us with higher gas prices, and really would be dumped better with our other projects.

Noel Parks – Ladenburg Thalmann

Great. That’s all for me. Thanks.

Edward Cohen

Thanks.

Brian Begley

This is Brain, just to acknowledge I’m staying that there is similar problems on the call. And then we’ll have Sean’s. So we apologize for that. There was an issue with the called service for about a minute or so. We’re happy to address any additional questions regarding it, that was missed on 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 picture, and Brian, thanks for galloging [ph] that drop up. Can I ask – I think we were dropped off during Sean’s comments about maintenance CapEx. Sean, could you perhaps briefly share with us your comments on the yield CapEx and maybe you are going to talk about the 2014 outlook for that line item.

Edward Cohen

Sure, absolutely. I mean, I essentially enjoy my comments, so just explain me, maintenance capitals to do the same things, it’s been last quarter just about private class wiper, new people are on the call, but I think of a range $45 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 or M&A at present using your goals to reduce the leverage that we heard? Does the echo said all, and EBIT your ability to be a continuously active in M&A, if you could frame that for us, that’s be helpful.

Sean McGrath

Sure, yes. I didn’t know we were looking at the M&A market, there is some great potential out there. We see a lot of good opportunities that will be complimentary or business. Obviously we’re very focused on adding the correct aspects with the appropriate decline, prices with the good. And 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 they are conservatively financed. I think if we stick to that pattern, when you look at our leverage, and you look at the deed [ph] we have come along with a great drilling activity, the managed teams are doing. I think leverage will naturally decline during the courses of the year but as I said, you know, pro forma for the cash, for the partnership programs we were down 3.81 times at this year-end. We’re expecting to year the year around, 3.6 times at 2104 and in that range. So, I think with the M&A market, I think if we just speak to our conservative approach how we’re file affinity, you know the transaction is also accretive, the BSF per unit and additionally, how to flow our leverage.

Michael Gaiden – Robert W. Baird

Great, thanks Sean. And can I maybe ask – how do you see the infrastructure in the Utica and Marcellus bathing if at all in the coming year?

Matthew Jones

There are infrastructure projects that are now approved and are being by funded by some of the major midstream companies in the Appalachia Basin. I think that there is going to be some relief coming forward in future period as a result of very substantial capital investments which is being made by pipeline companies in the Marcellus. So obviously oil companies’ will – that operate in that region will benefit. One thing that’s interesting to note – by the way, your question brings to mind, we – had we been under restriction expanding in the Appalachia region because they – non-competing agreement we had that persisted from a former transaction that we had done with Chevron number of years ago. That non-compete agreement expired about 10-12 days ago which was a very significant event for our company because we have a great deal and better knowledge associated with Appalachia. We were one of the first developers, the pioneer if you will develop in the Marcellus Shale a number of years ago. We have probably 250 or so wells that we’re operating today in southwestern Pennsylvania, in Green Country, Jack County, Washington County.

So we have deep and better knowledge in the Marcellus play. We now have had restrictions removed, it limited 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, the right opportunity surface, to take advantage of all of that. I think – that we will continue from the midstream side, relief will continue, and the gas will move around the country to where it’s needed. Here I think infrastructure clearly is coming in many projects that have been announced that are being funded.

Michael Gaiden – Robert W. Baird

All right. Thanks Matt and thanks Sean for your comments. That’s it for me.

Matthew Jones

Thank you.

Sean McGrath

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.

Matthew Jones

John [ph].

John Ragozzino – RBC Capital Markets

Mark, you provided some color on the fourth quarter of 2013, impact from the weather and – can you try to little bit more color on what the 2014 first quarter impact might be in terms of production volumes or cash flow impact from the weather?

Mark Schumacher

John, at this point we’re still trying to quantify the storms in February – the storms in the early part of the year had a bigger impact and February had a slight impact, really in January, really February was the biggest impact. We’re really – the end of February, we’re still kind of quantifying the numbers and putting them together. So, we’re going through that process and trying to just make sure that we get the most accurate number in terms of that. I don’t really have anything to provide you right at this point in time but we’re going to be actually working for that, both, the accounting financing teams as well as the operational teams to see really where it’s at. I think Matt’s team, and Matt can talk about this. He has really done a great job bringing those volumes back online as quickly as possible given all the promise we had during the period.

John Ragozzino – RBC Capital Markets

Right, just giving us some interim update, when you’re do going to boil down to the reliable number?

Mark Schumacher

We haven’t talked about that yet, I mean if we have something that – at a point in time before the first quarter earnings call, we will definitely discuss that in terms of whether we want 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 and the Mississippi Lime, yesterday they gave a brief update or a brief bump to their tight curve assumption on their UR which is about 38 MMboe. Can you just judge 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 saying?

Mark Schumacher

The SandRidge Company has an acreage position to reversing the crow [ph], something like 1.7 million acres, that SandRidge has defined is the Mississippi Lime play. I would suggest that our acreage is in what I believe SandRidge would also characterize is the core – if not the core then the core of the core, of the play. And so as far as the UR assumptions are concerned to a degree, and when we first get started, and this just continues today. It started in our development of the Mississippi Lime play, we leaned on tight curves that SandRidge was using. What we have found, and we haven’t changed by the way our type of group assumption which is all about – actually little bit lower than the number that you just mentioned that SandRidge is now using. But what we’re experiencing is higher production than the tight curve would suggest. So I’m hopeful certainly that that will continue which will lead us also to bump up our tight curve assumption in future periods.

John Ragozzino – RBC Capital Markets

And just as a follow-up to that question. Over the last of couple of years they’ve had some real trouble with giving a good handle for the different product streams than the associated decline rates and the positive number of revisions. Have you seen anything that I guess that’s materially different from your expectations when it comes to the oil decline rate relative to how fast gas volume declines or is it something that you’ve been aware of?

Matthew Jones

It’s not something that we’ve necessarily seen and on our property it’s been our production and I don’t – I rather not jump speculate on what SandRidge has experienced and where they’ve had their experiences. But, my speculation is that one of the reasons that SandRidge pulled back to their core areas was because they were getting, probably getting better production in the core area compared to some of the trend areas where they were testing and they have been experiencing higher components compared to liquid component. Potentially higher decline, I don’t know that for a fact that speculation but that maybe his game.

John Ragozzino – RBC Capital Markets

Thanks. I’ll move on. I don’t want to pick up, I’m not for anything in specific. Add just one more on the partnership program, you guys mentioned a target of $200 million in 2014. I am huge of fan of the program, once I finally get my arms around, I’m understanding all the benefits there that provided you guys. But allow me to play that because I think [ph] if there was excessive demand beyond that $200 million for 2014, is there a potential risk that the portfolio decline rate may experience some undesired inflationary pressure plus inflationary pressure driven by excessive wells drilled in place such as the Mississippian?

Matthew Jones

I would say that the $200 million figure is the figure that we buy today, it’s not a target figure in a 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 rip on to last year’s program and other factor. We can easily handle the $300 million.

John Ragozzino – RBC Capital Markets

I guess, let me just re-word the question just as a slightly. If you did have excessive demand beyond $200 million and that had the opportunity to deploy significant capital above that in those place, would you choose to do so or would you lead your activity levels at kind of where you budgeted at the risk of maintaining a portfolio decline rates, that’s more manageable.

Matthew Jones

I don’t think the portfolio decline rate is the 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 budgeted $200 million and on the other hand are not pleased if we are not submissive and our instincts are submissive [ph].

Mark Schumacher

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

Matthew Jones

John, I also mentioned that when we look at our overall growth strategy, drilling the punch programs or one half of that order two thirds of it – you know, we also look to grow through acquisition acquiring low decline, PDP oriented properties. So the combination is to as we continue to grow. That drilling program, the one-third that we in it as well as direct drilling, it becomes a smaller percentage of the overall growth. So you’re growing like an EP Acquisition which has made 10% decline. And you’re adding wells that you have a third interest with the partnership programs that have the decline profiles associated with them, your overall declined portfolio. He’s going to be unpacked by raising additional $50 million to $100 million of partnership per fare.

John Ragozzino – RBC Capital Markets

That’s exactly what I was looking for. Thank you very much. And just two real quick, it’s been housekeeping ones. When do you expect the file to KN who is only a plan in place for the next 12 months to possibly hold some Analyst Day or that would give us a little more of an opportunity to come and check the tires [ph] a little bit?

Matthew Jones

John as we do on a regular fashion, we’ll have group meeting for the investors and no definitive plans for a larger Investor Day at this point, so it’s nothing that 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 blocks to update our plan and strategy for the rest of the year and the case should be filed in next couple of hours.

John Ragozzino – RBC Capital Markets

Fantastic. Thanks a lot guys.

Matthew Jones

Thank you, John.

Mark Schumacher

Thanks, John.

Operator

(Operator Instructions). And our next question comes from the line of Craig Share with Chewy Brothers [ph]. Please proceed.

Unidentified Analyst

Morning guys.

Matthew Jones

Morning, Craig.

Unidentified Analyst

Congratulations on a good quarter. So let me just take you back on John’s question around the partnership raise. You know the increase was certainly helpful, year-over-year, but perhaps a little anticlimactic given the fact that last year it was down from the sloppy or the prior year, and in this period we have rising gas prices into the end of the year that obviously accelerated. We had 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 raised for this year, what do you think the obstacles were previously and what should get us over the home because I know you’ve done twice that historically some years ago.

Edward Cohen

That’s an excellent point, Craig. This is Ed. Prior to the Chevron family consistently raised without great effort, we had written without great pressure, $350 million to $450 million. The Chevron sale eliminated our ability to immediately provide acreage because when we came out with the new company, we had very limited aspects. So I think that the disappointment that investors had when we were at naively just figured using other joint ventures partner, we assume that they might not do as well as Atlas but they would do okay. That was a disappointment to us, to the investors. Now for the first time, investors are getting the results, very favorable results of Atlas, its own program, and I think that really takes still for the hub. That’s why $200 million to be conservative expectation, and I think that in the future there is no reason why we would not get back to an even XP focusing previously.

Unidentified Analyst

That would be great to see and it’s a big part of the story so I’ll keep an eye on that. Also, a little bit surprised about maintaining reduced distribution guidance from last October in light of – to Sean’s point, the rising commodity price tailwind that obviously is helping at least first quarter 2014. Can you discuss your price deck assumptions for the rest of the year versus current market, your basis spread assumptions, and what you’re distribution policy is as it relates to these kind of commodity driven fluctuations or windfalls if you will?

Edward Cohen

Craig, this is Eddy. Before Sean 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 will 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, remember that for gas we’re hedged over 80%, probably 80% to 85%, same with oil, both are very solid prices. On the NGL side when you look at heavier, we’re probably 55% plus hedged and the propane will probably in the – I’d say 75% hedge range. So, we’re hedged at very good prices for 2014. So while the uplift in prices, it’s helpful to an extent, it’s – we’re heavily protected, already at good prices. So this helps us with our unhedged volume, so we will see on the day certain impact of that but not where the original prices were going back to prior – mid of 2013. So we expect it will hopefully stay there, we’re going to look for good opportunities in walk in those prices but we’ve already protected ourself against that, potential downside movements.

Unidentified Analyst

Okay, fair enough. And this might be a good opportunity to don’t tell this question with some of the prior questioning, I think it was novice comments about commodity prices and the opportunities, they are developing some of the gas fear areas and I think that commented on the Barnett. One of the things though is, we’re seeing short-term movements, I mean turbo charged, but the 2015 and 2016 and beyond strips haven’t moved out much. And if you’re going to think about a drilling program, multi-year program. You obviously, historically have shown that they want to hedge out your returns and prove that you have some level of guidance cash flow and distributions for investors. What do you need to see, I guess this is directed more demand. What do you need 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.

Matthew Jones

Well, the financial results thing we need to see, Craig is the – we’ll undertake the analysis and we’ll allocate capital according to what we believe will be the highest returning project that we have. And so, for the gas project, the dry gas project, which what exception probably of our Lycoming project which is unique in it’s – in the ability to generate volume per dollar of investment for the other gas projects simply, for our capital allocation internally, or simply going to have to be competitive with the more oily and liquid oriented location. So when that occurs, what the crossover point will be is based on a variety of dynamics including natural gas prices, currently including natural gas prices on the 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, and I think 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 stores levels, producers are going to have to be induced by price to drill, to refill storage levels. But beyond, say the first, early into the second quarter of next year, the forward curve is backdated [ph]. And I think that that will probably prove to be inaccurate, that forward prices after the first quarter of next year are likely, ideally 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 advanced to the point that it substantiates allocating capital to dry gas locations, in the way the oil relocations, we’ll certainly do that.

Unidentified Analyst

Matt, I really appreciate 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. So if you’re thinking about garnering 20%, 30% IRR’s, at what level do you need to be able to hedge out long-term strips to join the Barnett in the gas results?

Matthew Jones

Well, I think the Barnett in particular, I think gas prices are in the $4 range and that potentially moving to a contained [ph] position from there causes the Barnett to be economic. Whether the Barnett becomes economic at those levels, it’s competitively economic with some of our other opportunities, it’s something we have to evaluate if one of that condition prevails. I think that part of the ability – if we had more capital and 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, the Mississippi Lime, the oily Marble Falls, the high returning dry gas areas in the Marcellus, etcetera, those areas we’re really focusing our capital today.

Edward 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 lot of people who believe that the future’s markets since the efforts to drive major banks out of playing the role in the commodities markets that they’ve played in the past when they were able to 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 the 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 well desire to purchase our acreage, and that’s another element that may take place.

Unidentified Analyst

Thanks Ed, that’s an excellent point. All I’ve got here my last question, it relates to AGP, if you’re able to answer it, 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’re not anywhere close to the original $300 million at this point, are you?

Edward 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 bothered 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.

Unidentified Analyst

Understood. Thanks again for all the answers.

Edward Cohen

Thanks, Craig.

Operator

And our next question comes from the line of Sean Sedam [ph] with Oppenheimer. Please proceed.

Unidentified Analyst

Hi, good morning. Thank you for taking my questions.

Matthew Jones

Hi Sean, no problem.

Unidentified Analyst

Ed or Sean, could you maybe talk a little bit more about the M&A environment that you guys are just seeing out there? Income, do you feel are more of the income from EP deals out there or are you guys more focused on the GeoMet type of transactions early for this year?

Edward Cohen

I think those deals basically differ in size, the motivation also differ based on somebody’s particular corporate situation if an acquisition has been made and they are dispersing – they are disposing some of the properties. But the overall market I think is really strong, there are lots and lots of GeoMet type deals available, obviously there are fewer deals in the larger size but those deals are present, all right. 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 – do what’s best for the company, but my failure to complete a deal will not reflect the fact that there aren’t lots of opportunities. Daniel Herger, [ph] are you still on the call?

Unidentified Company Representative

Yes, I am Ed.

Edward Cohen

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

Unidentified Company Representative

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 lots of the E&Key [ph] companies that are divesting of assets that we would define 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 lives and looking to divest of those assets.

Unidentified Analyst

That’s helpful. Maybe you guys think – maybe you can comment if I’m thinking about this right then you’re probably on the margin than your preferences first on this call, if you feel there is more value in less field price competition, and is that a fair assumption?

Matthew Jones

We do lean in that direction, but every time you start leaning in that direction, you’re amazed, at least I’m talking from a pays, when suddenly a fantastic deal comes along that’s properly priced, often for reasons that we could not anticipate it. And so the past is any guide to a future, it’s hard to predict just where we’ll wind up, but it’s really nice to know that there are lots of opportunities.

Unidentified Analyst

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’m sorry, unit product – yes, it’s quite early [ph] and cost per unit, yes, that’s right. I think overall if you look at 2014, it’s probably in the $1.05 to $1.15 area, it really depends upon the timing and level of the oils production, the liquids production that we have coming on. Obviously, as liquids production increases, it’s going to raise that number up because you’re using even though more valuable units, fewer units to spread the cost.

Unidentified Analyst

Okay, I appreciate that. And then just one last quick one, maybe for Matt. Do you think your Miss Lime acreage is perspective for additional zones, you have SandRidge to talk about themselves from other returns there, are you guys going to test any this year?

Matthew Jones

That’s an excellent question. It gives – I forgot to mention that today it was – in particular, SandRidge has announced that they’re gravitating towards the service stat pay approach if you will to drilling on their units and we’re watching what they’re doing. It has merit we believe because the Marble Falls, pardon me, the Mississippi Lime was particularly sack [ph] where we operate, so we think they are probably our opportunities to drill inimitably on a unit between the shallow sections of the formation and deeper sections of the formation. It’s interesting is that it’s kind of offsetting flanking our property, sort of the east to where we’re located, there has been some 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 – the intermittent staff pay approach if you will or the Woodford where we are very very closely watching on what’s occurring around us and I’m pretty excited about it, we’ll see what occurs but now we’re not allocating capital in that direction yet.

Unidentified Analyst

Okay. I appreciate that, it was helpful. Thank you, guys.

Matthew Jones

Thank you.

Operator

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

Edward Cohen

I thank 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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