Atlas Energy's CEO Discusses Q4 2012 Results - Earnings Call Transcript

Executives

Brian Begley - VP, Investor Relations

Ed Cohen - President & CEO

Matt Jones - SVP & President & COO, E&P

Sean McGrath - CFO

Analysts

Michael Peterson - MLV & Company

Craig Shere - Tuohy Brothers

Praneeth Satish - Wells Fargo

John Ragozzino - RBC Capital Markets

Wayne Cooperman - Cobalt Capital

Atlas Energy (ATLS) Q4 2012 Earnings Call February 22, 2013 9:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Atlas Energy and Atlas Resource Partners Fourth Quarter and Year-End Earnings Conference Call. My name is Anne, and I will be your coordinator for today’s call. As a reminder, this conference is being recorded for replay purposes. At this time, all participants are in listen-only mode. (Operator Instructions) We will be facilitating a question-and-answer session following the presentation.

I would now like to turn the presentation over to your host for today's call, Mr. Brian Begley, Head of Investor Relations. Please proceed sir.

Brian Begley

Good morning, everyone, and thank you for joining us for today's call to discuss our fourth quarter and full-year 2012 results. So as we get started, I would 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.

I would also like to caution 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 and maybe made to reflect the events or circumstances after the date hereof or reflect the occurrence of unanticipated events.

In both our Atlas Energy and Atlas Resource earnings releases, we provide reconciliation from net income to adjusted EBITDA and distributable cash flow, as we believe that these non-GAAP measures offer the best means for evaluating the results of our business.

And lastly, we will be participating in several upcoming investor conferences among other events including the Morgan Stanley Corporate Access Day in New York on Tuesday March 5th and the IPAA OGIS East Oil & Gas Conference also in New York on April 15th to the 17th.

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

Ed Cohen

Thanks and hello everyone. Let me just put it simply; 2012 was an incredibly successful year for Atlas Energy LP, ATLS, for Atlas Pipeline Partners and for Atlas Resource Partners, which are referred to as ARP, and this year, 2013, should see an acceleration and enhancement in my opinion of our accomplishments.

Over the entire range of criteria applicable to Energy Partnerships, and that’s return to unit holders, levels of distributable cash flow, growth in reserves, growth in level of production and processing, acquisitions and corporate development, handling of safety and environmental concerns, over this entire range, ATLS and ARP achieved outstanding results in 2012 and I believe set the stage for further triumphs in 2013.

Specifically, we're now reiterating ARP guidance for 2013 of distributions of at least $2.35 per unit. ATLS will distribute in 2013, $1.70 to $2 per unit. These projections of course are based on the assets we currently own and the projects that we already built or have set in motion, but you know we're certainly not a status quo enterprise and I think that you would expect us now to undertake and achieve additional favorable initiatives in 2013.

Now look at what we did in 2012. First, unit holder return; in contrast to the loss of approximately 8% for the overall E&P index, the [EXP] during 2012 and that was a horrendous year generally for E&P stocks; Atlas Resource Partners, ARP stock increased in price about 12% during its abbreviated 2012 year; remember it started in March. That was from the $20 punitive price at which it was spun-off in March to its closing price of $22.47 at year-end. ATLS’ total unit holder return for 2012 was 61%; I repeat that 61%. Median peer-group total return for the year was 3%. This strong increase in shareholder value for the year 2012 is especially impressive, because ATLS’ stock price total unit holder return had already increased 67% during the prior 2011 year. This stock market success happily reflected in my opinion true underlying operational achievements.

And now let me touch on some of these highlights. First of all, distributable cash flow. In 2012, ARP generated distributed cash flow of $72 million, a 50% increase over the proforma of $47.86 million for the prior year. Atlas Energy’s fourth quarter 2012 cash distribution of $0.30 per unit represented 25% increase over the corresponding prior year period.

Now let's turn to growth in reserves; ARP’s proved gas and oil reserves for its own account more than quintupled during the year from 167 billion cubic feet equivalent to 910 billion cubic feet equivalent, an increase of over 445% calculated on the basis of NYMEX forward strip prices. Reserves now achieved levels that had been attained prior to the 2011 sale of the old Atlas Energy to Chevron for $4.3 billion.

Atlas Resource Partners further manages and is paid for managing approximately an additional 300 million cubic feet equivalent of reserves owned by Atlas sponsored investment partnerships and another approximately 300 million cubic feet equivalent, I mean, for industry partners, that’s a total of 1.6 billion cubic feet equivalent of reserves under ARP control. During the 2012 year ARP acquired 136,300 acres of energy rights and over 1,200 drilling locations representing a potential $2 billion in future partnership fund raising to the extent these locations are not drilled directly by ARP or its own account returned to other profitable advantage by ARP.

Let's look at growth in volumes produced and processed. During the year 2012, ARP almost quadrupled natural gas production for its own account, from 35 million cubic feet equivalent per day to 130 million cubic feet equivalent per day. Daily production likewise now exceeds the level reached prior to the Chevron sale. Also during the 2012 period, 80 ATLS increased gathered volumes year-over-year and its processing subsidiary. Atlas Pipeline Partners that's APL increased it increased to 860 cubic feet equivalent per day, an increase of 40%.

Processed volumes at APL similarly grew some 40% through 769 million cubic feet equivalent per day. APL of course continues to enjoy unprecedented success in the liquids rich booming areas of Texas and Oklahoma were it operates in the Woodford and Permian basins and then the Arkoma Basin and in the Mississippi Limestone.

Processing capacity at APL has already more than doubled to over 1 billion cubic feet per day and with the opening of our new (inaudible) in West Texas should be in the next month or so increase a further 20%, the 1.2 billion cubic feet per day. In current, this growth in capacity and processing should of course result in appropriate increases in distributions on the APL common units and IDRs held by Atlas Energy, ATLS.

Let me talk about acquisitions and synergies. During 2012, ATLS executives consummated over $1.3 billion in accretive acquisitions, $700 million at ARP and $600 million at APL. Activity remained strong and opportunities right now are truly prolific. Under current conditions, we are optimistic that our 2013 acquisitions accomplishments will compare quite favorably with those of 2012.

Furthermore, ATLS, ARP, and APL are increasingly enjoying synergistic interaction. One example, APL strong growth and processing in the Mississippi Limestone has been paralleled by ARP's acquisition in 2012 of 20,000 net acres in the core of the Mississippi Lime. Now, ARP already has 16 wells in various stages of development in this play all of which should be producing by the early summer and Matt Jones will shortly describe this in what I consider to be exciting detail.

By June, ARP's investment in this area should be approaching $120 million and the insights supporting ARP's investment have been strongly aided by APL's presence here. Similarly, APLS expects in 2013 to be developing an innovative new limited partnership vehicle.

This new vehicle will benefit Atlas Resource Partners by offering an outlet for the excess landholdings that ARP routinely obtains ancillary to its acquisitions of cash flowing entities with long lived slow declining existing production.

ARP will benefit from the additional liquidity generated thereby and from the availability of programs other than the tax oriented investor funds that ARP's traditionally offer. This provides the Atlas companies additional protection of course from the eternally trumpeted efforts to prevent North American progress toward energy independence through adverse changes and tax provisions that presently benefit the energy industry.

I want to also talk about something very important and that’s the stellar safety record we had in 2012. In short, 2012 represented ATLS’ safest year on record. In the E&P area, incident rates were the lowest since record keeping began in 2005.

In processing and gathering, APL experienced the lowest number of safety incidence, again since record keeping began in 2007. Overall and I am quite proud of this, the company suffered not a single significant health or safety violation during the year. So much for the overview.

Now Matt Jones, Head of our E&P division will discuss E&P operations in some detail and Sean McGrath, our CFO will similarly cover financial issues. Matt?

Matt Jones

Thanks, Ed, and thank you all for joining our call today. The fourth quarter of 2012 concludes an outstanding year for Atlas Resource Partners. A year we improved reserves by more than 400%, an increased average daily production of natural gas, oil, natural gas, liquids collectively by more than 300%.

We diversified our base of reserves and production across basins and regions through strategic acquisition and organic growth, highlighted by our acquisition of oil and gas assets in the Barnett Shale and Marble Falls regions of the Fort Worth basin.

We also expanded into a number of other highly coveted plays in the United States, including the Utica Shale, Mississippi Lime and Marcellus Shale. As a result, we have greatly expanded our inventory potential drilling locations throughout our company including highly perspective, liquids rich opportunities.

We believe that we now hold more than 1,200 potential drilling locations across our acreage, many of which are held by production and benefit from potential oil and liquids production. We have also added outstanding talent to our team of seasoned oil and gas professionals who brought with them successful histories of asset development and operations in multiple basins particularly in areas of recent of our recent expansion. All these actions led to meaningful growth in our cash flow and cash distributions per unit through the course of the year in 2012.

Our actions in 2012 are also set the stage for substantial growth in our cash flow in 2013 and create the opportunity for organic growth for many years to come. We are focused on the efficient development of our exciting drilling opportunities for the benefit of our company and for those who invest in our direct investment programs. Also as Ed mentioned, we are dedicated to finding creative ways of establishing new avenues to bring forward value from our numerous undeveloped drilling inventory, but with equal importance, we continue to focus on minimizing costs and maximizing production from our existing wells in today totaled more than 10,000 across our system.

Operationally in fourth quarter 2012, we focused our drilling efforts in the Barnett Shale, the Utica Shale, the Mississippi Lime and the Marcellus Shale. Our drilling efforts and activity in the Utica, Mississippi Lime and Marcellus are being funded through capital that we raised in our Series 32 direct investment program that closed in the fourth quarter of 2012.

I’ll address the successful progression of our efforts in those areas in a moment but I will first address our highly satisfying activity in the Barnett Shale. The vast majority of our drilling to-date in the Barnett Shale has been funded directly from ARP’s balance sheet and our drilling efforts have been directed primarily to liquids rich sites located in developed pad sites and to a lesser extend on high returning gas, dry gas locations that also benefit from developed infrastructure reducing incremental capital cost per well.

The development of these assets is progressed very well as without connected or cleaning up through pull back 19 of the 26 wells included in our Barnett drilling program. Importantly, we’ve succeeded in reducing our well cost by more than 10% compared to our budget for Barnett wells with low cost averaging roughly $2.3 million.

The initial 30 day production rates for these wells have averaged approximately $2.5 million cubic feet equivalents per day. The addition of the Barnett wells to our system is the primary factor driving the recent incremental growth in our company's net production.

Atlas recently achieved the highest daily rate of production in its history producing over a $137 million cubic feet equivalents per day net to the company's interest.

The seven remaining wells in our 26 well programs in the Barnett Shale are scheduled for connection around the end of March of this year. Beyond our initial 26 well Barnett program, we've a substantial number of remaining drilling locations in our Barnett Shale acreage that are largely held by existing production allowing us the luxury of optionality associated with the pace of future development.

Another very exciting area of development for us in the Fort Worth basin is our Marble Falls position which is generally located roughly 70 miles north and west of our Barnett Shale assets in our Fort Worth operations office.

In mid-January, we initiated drilling of our 50 vertical well drilling programs currently designated for 2013 in the Marble Falls. We currently have six wells in various stages of drilling and completion and we connected our first two wells this week. Although, its are early days for us in the Marble Falls, I am very pleased to report that our first 24-hour production rates on average for the first two wells exceeds 85 barrels per day of crude oil and approximately 300 Mcfe per day of liquids rich gas per well and these wells are getting stronger and production is climbing.

Also worthy of notice, our average well cost, when we closed on our acquisition of the Marble Falls assets last year, we had assumed average well cost of $850,000 per well consistent with the previous owners results. So far under Atlas ownership and the direction of the Atlas development team led by Mark Schumacher, I'm happy to report that our average well costs are coming in 10% or more below budget in the $750,000 to $770,000 range.

With respect to a 50 well program this year, and with potentially as many as 700 or more drilling sites to exploit on our Marble Falls perspective acreage, cost savings on the entirety of the development of our position are potentially quite meaningful and we anticipate that the impact to returns on invested capital in the play will be sufficiently significantly enhanced relative to already high expectations based on historical results in the play. We are we expect about our Marble Falls investment and we will have more information to share on its development in the coming months.

We are equally excited about our ongoing development activities on our Mississippi Lime acreage, our Utica shale acreage and our Marcellus shale position. In the Mississippi Lime, we are in various stages of drilling and completing 16 wells and we currently have two wells that have been producing for 120 days in one case and 170 days in the other. These wells have averaged about 225 barrels of oil equivalent per day per well and this level exceeds our original expectation for this period. In addition, we have two wells that have recently been brought online with very limited production history and we will provide updates on these wells in upcoming periods.

As a precursor to those reports with some of our recent horizontals we've encountered continuous and strong oil and gas shows in nearly the entirety of their roughly 4000 feet of effective lateral section. We expect to have most of the 16 wells that are in the current development stage producing by late June and we will be reporting on our progress here in upcoming periods. The vast majority of these wells are being funded through our recently completed Series 32 Direct Investment program.

Our 20,000 net acres perspective for the Mississippi Lime is located in core of the play in Alfalfa, Grant and Garfield Counties and our position is offset by Mid-States, formerly Eagle Energy, SandRidge Energy and Chesapeake Energy. Nearly the entirety of our acreage is held by our Hunton formation rich gas production that underlies the Mississippi Lime formation. Based on five wells per section, we believe that we have more than 125 drilling locations perspective for the Mississippi Lime on our acreage.

Moving to Appalachia; we continue to lever our long standing and successful operating history and significant presence in the region. Beginning with Eastern Ohio where we have several field offices and roughly 2500 producing wells. We currently have under lease roughly 4500 acres of Utica Shale perspective properties located in Harrison, Tuscarawas and Stark Counties. Some of our E&P peers continue to escalate permitting and drilling activity in the Utica bolstered by very exciting initial well results, Midstream development continues at an advanced pace and perhaps no other area is more promising than the Harrison County area where Gulfport energy, Chesapeake Energy and others continue to report substantial initial well results ranging from 1300 Boe per day to more than 3300 Boe per day.

As a result, we focused our initial development activity in our Harrison County Utica/Point Pleasant position where we are in advanced stages of drilling five wells from a single pad site, and where the geology benefits from over 120 feet of thickness of greater than 5% porosity in the Point Pleasant section of the Utica Shale. The degree of thickness and porosity compare very favorably to the areas where the best wells in the region have been drilled.

With effective lateral lengths on average approaching 6,000 feet, we're on schedule to complete the drilling of the wells late in the first quarter and to initiate our completion operations at that time. The full lateral length of the first of the five wells was recently completed and we're quite encouraged that we have carried almost continuous strong oil and gas shale for nearly the entirety of the effective lateral length. We expect to have our five Harrison County wells producing by late in the second quarter or early in the third quarter following completions and arresting or dissipation phase. All these wells are being funded through our Series 32 Direct Investment program.

On our Marcellus shale acreage located in Lycoming County in Northeastern Pennsylvania, we have significantly advanced drilling of our initial eight wells in the area located on two pad sites. We’ve nearly completed drilling and we will soon begin the sequence completion process of the eight wells; much like our Utica wells, we're quite encouraged by frequent and strong gas shows in the effective lateral lengths of these wells.

Also recent wells results announced by range resources in Seneca in close proximity to our well sites have come online with initial production rate exceeding 10 million to 15 million cubic feet per day and in some cases, exceeding 20 million cubic feet per day. Coincidentally, we expect to have production from these wells on or about the same time as our connection of our Utica wells. Our Marcellus well activity is also being funded through our Series 32 Direct Investment program.

Lastly, our proved resources have increased exponentially over the course of 2012. Based on current NYMEX pricing, as compared to SDC pricing, which employees flat natural gas prices of $2.76 per Mcf, we ended the year with approximately 911 Bcfe of proved reserves with a present value of nearly $1 billion. This represents an estimated reserve life roughly 19 years based on recent production level. Also the state of prove reserves net to our company’s interest excludes the proved reserves that we manage for those who invest in our direct investment programs and those investors payout let’s say fee for the ongoing management of those reserves and related production.

At year-end reserves that we manage for our partners in our direct investment programs total approximately 300 Bcfe and we generated net cash fees totaling about $14 million during 2012. This payment for operating wealth associated with our partners’ interest. These fees are ongoing for the life for the wells included in our programs that represent a stable long life source of cash fee income to Atlas Resource Partners.

In closing, I would like to send out a quick note of thanks to all of the very capable and hardworking people at Atlas who have contributed and continue to contribute to the success of our business. The quality and diversity of our oil and gas assets is matched by the quality of our outstanding people. Thanks to all.

Now to Sean McGrath, our Chief Financial Officer.

Sean McGrath

Thank you, Matt and thank all of you for joining us the call this morning. First, regarding ARP, we generated adjusted EBITDA of approximately $32 million or $0.66 per unit and distributable cash flow of approximately $28 million or $0.56 per unit for the fourth quarter of 2012. We distributed $0.48 per limited partner units of the period based upon these results representing 1.2 times coverage ratio.

Production margin for the fourth quarter of over 30 million representing a 175% increase compared with 11 million for the prior year fourth quarter and a 50% increase from the third quarter 2012. The fourth quarter included a full period cash margin from our acquisition of the DTE of over $10 million which was acquired on December 20th and generated approximately 4200 barrels per day of equivalents from the date of acquisition.

Overall production volume grew to 110 million cubic feet of equivalents for the fourth quarter, an approximate 15% increased from the third quarter and more than tripled from the prior year comparable period. The increase between the third and fourth quarters was due to the DTE acquisition as well as the full quarter’s production from Titan which was acquired in July.

Lease operating expenses for the period of $0.88 per Mcfe were over 25% lower compared with the prior year fourth quarter, as our low cost Barnett production and the higher Appalachia production volumes drove cost per Mcfe significantly downward compared with the prior year. LOE per Mcfe for the fourth quarter increased compared with the third quarter of 2012 although gross costs remained relatively consistent due to the increase in ARP oil and NGL production between periods, as liquids accounted for approximately 20% of our production volume in the current period, compared with approximately 10% for the third quarter, due growth driven by our Barnett, Marble Falls and Mississippi Lime assets. Overall, we expect liquids to account for approximately 25% of ARP’s 2013 production volume guidance of 51 billion to 56 billion cubic feet of equivalents.

Partnership management margin for the quarter was approximately 11 million, which is relatively consistent with the third quarter and reflects the continued deployment of capital for our 2012 program including wells in Utica and Marcellus Shale and the Mississippi Lime. For 2013, we expect to raise at least the $150 million in partnership investor funds compared with the $127 million raise in 2012, and expect to deploy approximately $190 million of investor’s capital providing ARP with significant fee based margin in the current year.

Moving on to general and administrative expense, net cash G&A was $9 million for the period which was consistent with the third quarter of 2012. As management continues their aggressively control cost more considerably expanding its operations.

Growth capital expenditures of $50.5 million for the fourth quarter represent an increase of $26 million compared with the third quarter of 2012. The fourth quarter included $23 million of CapEx for contributions through our partnership programs, a $12 million increase from previous quarter and $20 million of direct well drilling in the Barnett Shale that Matt mentioned previously, a $10 million increase from the previous quarter.

We expect to see considerable increases in production margin from both of these activities in the near-term. For 2013, we expect total capital expenditures of $175 million including approximately $26 million of maintenance capital consisting of approximately $145 million for well drilling activities, including our investments in the partnership programs and approximately $30 million for land leasing and other activities.

Also during the fourth quarter, I wanted to note that we recognize $9.5 million non-cash impairment in legacy gas and oil properties in our Michigan and Colorado regions, areas we are not currently developing.

Our forward NYMEX gas prices are at or higher than comparable prior year prices in the near term. Prices for 2017 which are required by accounting regulations to calculate the fair value for the majority of production from these regions were 5% 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. 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.

This is clearly embodied in our acquisition of DT assets during the period where we hedged 80% of proved developed producing production for 2013, 50% for the following 24 months and 30% for the outer years.

Overall, we have hedged positions covering over 105 billion cubic feet of natural gas production at an average floor price of almost $4.20 per Mcf for periods through 2017, including 2013 hedges covering over 90% of what we are currently producing consisting of a combinations of puts, swaps and collars to provide us with downside protection, but upside potential for natural gas prices.

In addition, we have hedged in average of approximately 65% to 70% of our current run rate crude oil production for the next four years at an effective average floor price in excess of $91 per barrel. We are committed to adding protection to our business and providing better 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.

Moving on to our debt and liquidity position, in January this year, we took the opportunity of favorable market conditions and strong track record to issue 275 million of senior notes at a price of 7.75 which represents a historically low interest rate for initial issue with respect to ARP size.

The net proceeds which were used to repay the term loan and credit facility borrowings incurred on the DT acquisition provided ARP with additional flexibility within its capital structure. As evidenced by over $290 million of pro forma liquidity at December 31, 2012.

Pro forma for the senior notes offering ARP's leverage ratio is below three times which provides us with ample capacity to execute our acquisition and growth strategy in the coming years.

In closing on ARP, I want to take a moment to mention with regard to ARP's stated cash distribution guidance for 2013 of at least $2.35 per unit. We expect a gradual increase in the current $1.92 per unit run rate during the first half of 2013 with significant increases occurring in the back half of 2013, reflecting the deployment of our 2013 partnership program funds and the connection of wells from our deployment activity in the first half of 2013.

With regard to Atlas Energy LP, we generated distributable cash flow of $15.5 million and distributed $0.30 per unit for the period, representing a one-time coverage ratio. Going forward, we expect ATLS to continue to maintain minimum coverage on its cash distributions, as ARP and APL both expect to maintain ample coverage ratios in future periods.

Atlas Energy Bcf included $6.5 million of total cash contributions from APL, representing an almost 25% increase from the prior year fourth quarter. These distributions included $2.3 million of incentive distribution rates, an increase of 65% from the prior fourth quarter as Atlas continues to share considerably in ATL’s growth.

Atlas Energy Bcf for the period also included $10.7 million of cash distributions from ARP, a 14% increase from the third quarter of 2012. ARP distributions for the quarter included approximately $200,000 from its incentive distribution rates. We expect this amount to increase significantly as ARP achieves its stated growth objectives in 2013.

Cash G&A expense for Atlas Energy on a standalone basis was $1.5 million for the period which is relatively consistent with the third quarter of 2012. For 2013, we expect Atlas standalone G&A expense to be approximately $7 million to $8 million, cost being higher in early 2013 due to the seasonality of expenses, including our annual shareholder meeting and compliance cost.

Finally, I would like to quickly mention Atlas’s strong standalone balance sheet, which has no debt outstanding and a $50 million credit facility of over $40 million availability. With that, thank you for your time. I will turn the call over to CEO, Ed Cohen.

Ed Cohen

Sean, I find it exciting every time I listen to you, keep it up. But now and I think its time for questions.

Question-and-Answer Session

Operator

(Operator Instructions) and our first question comes from the line of Michael Peterson with MLV & Company. Please proceed.

Michael Peterson - MLV & Company

Because growth is such essential component of the ARP story I would like to ask you to share your perspective on the asset markets, specifically if you could characterize the market environment in New Year and secondarily, where do you see the best value proposition for ARP in the coming quarters?

Ed Cohen

When you ask me about the markets, are you asking about prices or acquisitions?

Michael Peterson - MLV & Company

Acquisitions, sir.

Ed Cohen

This is Ed. I tried to make clear that we think it’s a very brilliant market for the type of products that ARP is looking for. It has continued into 2013 at the same favorable situation as in 2012. We are working very hard and I think we are confident that we will get our share of hopefully more than our share of good deals. The bad deals we will leave to others. The second part of your question, Mike?

Michael Peterson - MLV & Company

The second part is that where do you think that the best value proposition for your portfolio is whether that be regional or commodity mix?

Ed Cohen

Well we think the best value remains in those areas where people are constrained by their own economic situation and by the conditions under which they acquired assets that it sometimes they are overly leveraged and where we can get the best price and so we always look at the relationship between the price and value and that’s not necessarily the areas that others are excited about as there is (inaudible) fees goals now, we like to rush in where others are rushing away from as we find that's where the best value wise.

Operator

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

Craig Shere - Tuohy Brothers

I will try to limit myself and comes back in queue if there are other questioners, so I'll start off with a couple. Can you elaborate on this new non-tax driven LTE vehicle you are launching this year and perhaps explain a little more clearly I am sorry I didn't quite touch it, what relates to sizably that can achieve and how capital rates from that would be deployed?

Ed Cohen

I think you are going us to go back if you didn't catch it to the published and recorded versions because we are constrained by SEC regulations as what to we can say, I think we said was proper to be said and in due course all this will become clear.

Craig Shere - Tuohy Brothers

Fair enough, and I noticed the regional production data that or from the totaling of that which is little different than totals because of the acquisition accounting that liquids were 20% of the fourth quarter production from 8.5% of this quarter, can you comment on these trends heading into ‘13 and beyond?

Ed Cohen

Matt.

Matt Jones

Yeah, first Craig with respect to the fourth quarter we added liquids production through our acquisition in the Marble Falls and we also have full quarter, in the fourth quarter production from our acquisition of Hunton liquids rich production that took place at the end of the third quarter, so both of those dynamics positively impacted liquid production in the fourth quarter. Moving into 2013, we've shifted a good portion of our capital budget, the primary portion, a significant portion of our capital budget, drilling capital budget in 2013 to oil and liquids rich drilling opportunities and so we expect that the amount of liquids and oil with the oil that we’ll generate 2013 is going to increase pretty meaningfully. We are going to see some increase in our natural gas production also. So proportionately I would expect that we will have a higher proportion of our total production from oil and liquids in 2013 even compared to the fourth quarter of 2012.

Ed Cohen

Yeah, we are projecting to be about 25% of our total production to come from liquids which I mentioned in my comments, but yeah that's a rough percentage that we are anticipating.

Craig Shere - Tuohy Brothers

Sure, I assume since that's significantly driven by the drill that you would expect that trend to continue into ’14?

Matt Jones

I'd say that's the case, correct yes.

Craig Shere - Tuohy Brothers

Okay. And to add some insight upon my first question I'll throw one more out there and go to queue, a year ago you described yourself as more resource limited than funding limited. After $710 million of successful 2012 acquisitions, but a lower year-over-year private partnership raise, do you see this condition having at least temporarily reversed and would this indicate the need to focus 2013 acquisitions on more high PDP properties that can rapidly be absorbed on to the balance sheet?

Ed Cohen

I think that we are seeing a good flow of deals that really meet our essential requirements of being existing production with low decline and with good cash flow at the present time which is previously or likely to throw off additional areas for development. Well, I think that part is all favorable and I don't think we will have any difficulty in pursuing and accomplishing the acquisitions we are interested in. I think that 2012 was an extremely difficult year for tax oriented product, because as you know Congress did not actually take action until after the end of 2012. It’s a real tribute to our staff that we were able to place as much product and generate as much resources for drilling operations this year as we actually did accomplished in 2012. We don't anticipate, I don't think any anticipates the Congress will be going to January 2, of 2014 where they make their determination; so this year should be a lot better I think.

Craig Shere - Tuohy Brothers

Understood. Since you are seeing so much on the cash flow and properties that can be absorbed on the balance sheet and in light of the comments about how much capacity you have on the balance sheet that kind of Sean referred to, is it fair to say that highly cash flowing, heavily PDP acquisitions of 2013 might be more heavily debt financed than we saw in 2012?

Ed Cohen

I think each deal requires its own solution, so I wouldn’t want to make a general statement until we know what the deals actually are.

Operator

And our next question comes from the line of Praneeth Satish with Wells Fargo. Please proceed.

Praneeth Satish - Wells Fargo

I just wanted to clarify a point on the distribution guidance for 2013. In the past, you’ve noted a range of $2.35 to $2.50, but now it seems like the language has shifted a little with the distribution expectation of at least $2.35 per unit; am I thinking about this correctly or are you still comfortable with that $2.35 to $2.50 range?

Ed Cohen

I think we should be complimented by the attention you paid to our specific language. I think it's a chance factor that state is a little bit differently. Of course, we're still comfortable and when we say at least $2.35, we're not meaning to suggest that there is not a possibility of it being higher.

Praneeth Satish - Wells Fargo

Okay. And just one more question, can you provide any additional details around how the drilling budget in 2013 will be spilt, specifically, how much of that spending is for ARP’s own account in North Texas versus the partnership business?

Sean McGrath

It’s Sean; Satish, the budget has 145 to total CapEx for well drilling; 85 of that is for direct well drilling, which we are going to be splitting between the Barnett and the Mississippi Lime, including (inaudible) Barnett includes the Marble Falls. So the remainder of that approximately 60 million is going to go towards the partnership programs and so the contributions we make the partnership programs to fund it.

Operator

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

John Ragozzino - RBC Capital Markets

Can you quickly expand upon the comments made regarding the 2013 [NV] program and its comparison 2012, do you expected to compare favorably in terms of size or individual deal attractiveness?

Ed Cohen

You are asking about our anticipations on acquisitions?

John Ragozzino - RBC Capital Markets

You have just mentioned in your early comments just that the 2013 program was expected to compared favorably and I am just wondering is that in terms of total deal files for the full year or just be attracted in some individual opportunity that you see recently?

Ed Cohen

I think both. We expect volume to be high and I would be very surprise this if the quality was not at least equal to the outstanding quality we were able to pick up last year.

John Ragozzino - RBC Capital Markets

And would you walk through the Mississippi in development program, can you give any comments on the development of the pipeline you’ve seen as you have gotten some wells that have been online for a longer period of time since it’s (inaudible) with respect to the products and in any changes in your estimates?

Ed Cohen

I think Matt you are entitled to answer this one.

Matt Jones

Yes, John I would say that obviously we have drilled our first two wells in the Mississippi Lime; we have a substantial program in front of us. We continue to anticipate that our wells will be similar to those that are being drilled around us in the industry. We are surrounded by SandRidge and Chesapeake mid states and our expectation is that our wells will be very similar to and quite consistent what others are reporting. For our first couple of wells they continue to produce very nicely. We will add another 14, 15, 16 wells over the next three months, four months. It will still be relatively early for us but we have more to report on in the June and July timeframe.

John Ragozzino - RBC Capital Markets

And just one quick, I am sorry but I missed it, did you mention how long you guys are using and what kind of dissipation period that you are using in the Utica?

Matt Jones

Yeah, we are likely to use the 60 day period for our wells. We are kind of right in the middle of what most people refer to is the rich gas or what gas window and I think most have found so far that optimal results come about as a result of that duration of period for dissipation or seasoning.

Operator

(Operator Instructions) And our next question comes from the line of Wayne Cooperman with Cobalt Capital. Please proceed.