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

Q4 2012 Results Earnings Call

February 22, 2013 9:00 AM ET

Executives

Brian Begley - Head of Investor Relations

Ed Cohen - Chief Executive Officer

Matt Jones - President and COO

Sean McGrath - Chief Financial Officer

Analysts

Michael Peterson - MLV & Company

Craig Shere - Tuohy Brothers

Praneeth Satish - Wells Fargo

John Ragozzino - RBC Capital Markets

Wayne Cooperman - Cobalt Capital

Operator

Good day, ladies and gentleman. And welcome to the Atlas Energy and Atlas Resource Partners Fourth Quarter and Year End Earnings Conference Call. My name is Ann, 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. 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 [technical difficult] 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 discussed these risks in our quarterly report on Form 10-Q and our annual report also on Form 10-K particularly in Item 1.

I’d also like to caution not to place undue reliance on these forward-looking statements which reflect management analysis only as of the date hereof. The company undertakes no obligation to publicly update our forward-looking statements or to publicly release the result, any revisions to forward-looking statements and maybe made to reflect events or circumstances after the date hereof or reflect the occurrence of an anticipated events.

In both our Atlas Energy and Atlas Resource earnings releases we provide a reconciliation from net income to adjusted EBITDA and distributable cash flow as we believe 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 and Gas Conference also in New York on April 15th to the 17th.

With that, I’d 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 succinctly 2012 was an incredibly successful year for Atlas Energy, L.P., ATLS, for Atlas Pipeline Partners and for Atlas Resource Partners which I’ll refer 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 unitholders, 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 build or have set in motion. But you know, we are certainly not a status quo enterprise and I think that you would expect us not to undertake and achieve additional favorable initiatives in 2013.

Now look at what we did in 2012. First, unitholder return, in contrast to the loss of approximately 8% for the overall E&P Index, the Ex-EPY 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 putative price which it was spun off in March to its closing price of $22.47 at year end.

ATLS’ total unitholder return for 2012 was 61%, I repeat that’s 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 unitholder return had already increased 67% during the prior 2011 year. This stock market success happily reflected in my opinion through underlying operational achievements.

And now, let me touch on some of these highlights. First of all, distributable cash flow. In 2012, ARP generated distributable cash flow of $72 million, a 50% increase over the pro forma of $47.86 million through 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 equivalent to 910 billion cubic feet equivalent, an increase of over 445% calculated on the basis of NYMEX forward strip prices. Reserves now exceed the levels that had been obtained 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 then other approximately $300 million -- 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 1200 drilling locations, representing a potential $2 billion in future partnership fundraising to the extent these locations are not drilled directly by ARP for its own account, returned to other profitable advantage by ARP.

Let’s look at growth in volumes produced in process. 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 sales.

Also, during the 2012 period, ATLS has increased gathered volumes year-over-year in its processing subsidiary, Atlas Pipeline Partners, that’s APL. It increased it to 860 million cubic feet equivalent per day, an increase of 40%. Processed volumes at APL similarly grew from 40% to 769 million cubic feet equivalent per day.

APL of course continues to enjoy unprecedented success, the liquids rich booming areas of Texas and Oklahoma where it operates in the Woodford and Permian Basin and in 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 driver plant in West Texas should in the next month or so increase a further 20% to 1.2 billion cubic feet per day. In turn, 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 remains strong and opportunities right now are truly prolific.

Under current conditions, we’re optimistic that our 2013 acquisition accomplishments will compare quite favorably with those of 2012. Furthermore, ATLS, ARP and APL are increasingly enjoying synergistic interaction.

The one example, APL’s strong growth in 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 surely describe this in what I consider to be exciting detail.

By June, ARP’s investment in this area should be approaching $120 million and insights supporting ARP’s investment have been strongly aided by APL’s presence here. Similarly, ATLS 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 land holdings 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 has traditionally offered. 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 in 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 a lowest number of safety incidents again since record keeping began in 2007.

Overall and I’m 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 grew proved reserves by more than 400%, an increased average daily production of natural gas, oil, natural gas liquids collectively by more than 300%.

We diversified by our base of reserves in production across basins and regions through its strategic acquisition in organic growth, highlighted by our acquisition of oil and gas assets in the Barnett Shale and Marble Falls regions in 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 greatly expanded our inventory potential drilling locations throughout our company, including highly prospective 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’ve also added outstanding talent to our team of seasoned oil and gas professionals who brought with them successful history of asset development and operations in multiple basins, particularly in areas of recent well lease and expansion. All of 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 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.

Of equal importance, we continued to focus on minimizing costs and maximizing production of our existing wells that today totaled more than 10,000 across our system. Operationally in the fourth quarter of 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’ll 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 site located on developed pad sites, and to a lesser extent on high returning dry gas locations that also benefit from developed infrastructure, reducing incremental capital cost per well.

The development of these assets has progressed very well, as we’ve now 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 costs by more than 10% compared to our budget for Barnett wells with well 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 your 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 137 million cubic feet equivalents per day net to the company’s interest.

The seven remaining wells in our 26-well program in the Barnett Shale are scheduled for connection around the end of March of this year. Beyond our initial 26-well Barnett program, we have a substantial number of remaining drilling locations on 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 Forth Worth operations office. In mid-January, we initiated drilling of our 50 vertical well drilling program 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 these are early days for us in the Marble Falls, I’m 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 350 Mcfe per day of liquids rich gas per well and these wells are getting stronger and production is climbing.

Also worthy of note is 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 year’s results. So far under, Atlas ownership and direction of the Atlas development team led by Mark Schumacher, I’m happy to report that our average well cost are coming in 10% or more below budget in the $750,000 to $770,000 range.

With respect to our 50-well program this year and with potentially as many as 700 or more drilling sites to exploit on our Marble Falls prospective 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 on the play will be sufficiently, significantly enhanced relative to already high expectations based on historical results in the play.

We are very excited about our Marble Falls investment, and we’ll have more information to share on its development in the coming months. We are greatly 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 equivalents per day per well and this level exceeds our original expectation for this period.

In addition, we have two wells that have been recently 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 selling our recent horizontals we’ve encountered continuous in strong oil and gas shows in nearly the entirety of their roughly 4,000 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 prospective for the Mississippi Lime is located in the core of the play in Alfalfa, Grant and Garfield counties and our position is offset by Midstates, formally 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 prospective 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 2,500 producing wells, we currently have under leased roughly 4,500 acres of Utica Shale prospective properties located in Harrison Tuscarawas and Stark counties.

Some of our E&P peers continued to escalate, permitting a drilling activity in the Utica, bolstered by very exciting initial well results. Midstream development continues at an advanced space and perhaps another area is more prominent and promising in the Harrison country area where Gulfport Energy, Chesapeake energy and others continue to report substantial initial well results ranging from 1,300 Boe per day to more than 3,300 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 size 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 is compared very favorably to the areas with the best wells in the region they’ve been drilled.

With effective lateral lengths on average approaching 6,000 feet, we are on scheduled 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 are quite encouraged that we encountered almost continuous strong oil and gas shows to 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, Northeastern Pennsylvania we’ve significantly advanced drilling of our initial eight wells in the area located on two pad sites. We’ve nearly completed drilling and we’ll soon began to sequence completion process of the eight wells, much like our Utica wells, we are quite encourage by frequent and strong gas shows in the effective lateral length of these wells.

Most of the recent wells results announced by Range Resources and Seneca in close proximity to our well site, they’ve come online with initial production rate exceeding 10 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 reserves have increase exponentially over the course of 2012. Based on current NYMEX pricing as compared to SEC pricing, which employes flat natural gas prices of $2.76 per Mcf, we ended the year with approximately 911 Bcfe approved reserves with the present value of nearly $1 billion. This represents an estimated reserve life of roughly 19 years based on recent production level.

Also the stated proved reserves net to our company’s interest exclude the proved reserves that we manage for those who invest in our direct investment program and those investors payout as a fee to the ongoing management of those reserves and related production.

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

In closing, I’d like to send out a quick note of thanks to all of the very favorable and hard working 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 on the call this morning. First, regarding ARP, we generated adjusted EBITDA of approximately $32 million or $0.66 per unit and distributable cash flow approximately $28 million or $0.56 per unit for the fourth quarter of 2012. We distributed $0.48 per limited partner unit for the period based upon these results, representing 1.2 times coverage ratio.

Production margin for the fourth quarter of over $30 million, represented 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, our acquisition of the DTE of over $10 million, which was acquired in December 20th and generated approximately 4,200 miles per day of equivalents from its date of acquisition.

Overall, production volume grew to 110 million cubic feet of equivalents for the fourth quarter and approximately 15% increase from the third quarter and more than triple from the prior year comparable period. The increase between the third and fourth quarters was due to the DTE acquisition, as well as 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 gross cost per Mcfe significantly downward compared with the prior year.

LOE per Mcfe for the fourth quarter increased compared with the third quarter 2012, although gross cost remained relatively consistent due to the increase in ARP oil and NGL production between periods, as liquid 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%, 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 Mississippi Lime.

For 2013 we expect to raise at least $150 million in partnership investor funds compared with the $127 million raised in 2012, and expect to deploy approximately $190 million of investor’s capital, providing ARP with significant fee base 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 2012 as management continues to aggressively control costs while 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 2012. The fourth quarter included $23 million of CapEx for contributions to our partnership programs, a 1$2 million increase from the 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 a $9.5 million non-cash impairment legacy gas and oil properties in our Michigan and Colorado regions. Areas we are not currently developed.

Our forward NYMEX gas prices are at or higher than comparable prior year prices in the near-term, prices for 2017 which were required by accounting regulation 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 risk management activities, we continued to execute our strategy methodically yet opportunistically mitigating potential downside commodity volatility for both our legacy and acquired production.

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

Overall, we have hedge 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 combination of puts, swaps and collars provide us with downside production but upside potential for natural gas prices.

In addition, we have hedge an average of approximately 65% to 70% 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 in 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 senior notes at a price of 7.75%, which represents a historically low interest rate per initial issuer with respect to ARP size.

Net proceeds which we use to repay the term loan and credit facility borrowings incurred on the DTE 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 below three times, which provides us with ample capacity to execute our acquisition and growth strategy in the coming year.

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

With regards to Atlas Energy, L.P., 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 distribution, as ARP and ATLS, both expect to maintain ample coverage ratios in future period.

Atlas Energy DCF included $6.5 million of total cash contributions from ATL 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 ATLS’ growth.

Atlas Energy DCF for the period also included $10.7 million of cash distribution from ARP, a 14% increase from the third quarter of 2012. ARP’s distribution for the quarter included approximately $2000 with an incentive distribution rates. We expect this amount to increase significantly as ARP achieved stated growth objectives in 2013.

Cash G&A expense for Atlas Energy on a standalone basis was $1.5 million for the period, which was 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, with cost being higher in early 2013 due to the seasonality of expenses, included in our annual shareholder meeting and compliance calls.

Finally, I would like to quickly mention Atlas’ strong standalone balance sheet which has no debt outstanding and a $50 million credit facility with over $40 million of availability at year end.

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

Ed Cohen

Sean, I find it exciting every time I listen to you. Keep it up. But now, Ann, I think it’s 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

Good morning, gentlemen.

Ed Cohen

Good morning, Michael.

Matt Jones

Hi, Mike.

Michael Peterson - MLV & Company

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

Ed Cohen

Are you asking about the markets or you asking about prices or acquisitions?

Michael Peterson - MLV & Company

Acquisitions, sir.

Ed Cohen

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

Michael Peterson - MLV & Company

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

Ed Cohen

Well, we think the best value remains those areas where people are constrained by their own economic situation. And by the conditions under which they acquired assets that is sometimes they were fully leveraged and where we can get best price.

And so we always look at the relationship between price and value and that’s not necessarily the areas that others are excited about. As those who listen to these calls know, we like to rush in where others are rushing away from because we find that’s where the best value lies.

Michael Peterson - MLV & Company

That makes sense. Thanks for your comments, Ed. And that’s all I have this morning.

Ed Cohen

Thank you.

Operator

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

Craig Shere - Tuohy Brothers

Good morning, guys.

Ed Cohen

Hi, Craig.

Matt Jones

Good morning, Craig.

Craig Shere - Tuohy Brothers

So I’ll try to limit myself and jump back in queue if there are other questioners?

Ed Cohen

Thank you.

Craig Shere - Tuohy Brothers

Start off with a couple. Can you elaborate on this new non-tax driven LT vehicle you’re launching this year and perhaps explain little more clearly. I’m starting to quite catch it, what it relates to the size, I believe, it can achieve and how capital raised from that would be deployed?

Ed Cohen

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

Craig Shere - Tuohy Brothers

Fair enough. And I noticed the regional production data 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, up from 8.5% of third quarter. Can you comment on these trendsetting 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 four quarter. And the fourth quarter production from our acquisition of Hunton liquids rich production that took place again 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 the good portion of our capital budget, priority portion, the 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 oils -- the oil that we generate in 2013 is going to increase pretty meaningfully.

We’re going to see some increase in our natural gas production also. So proportionately, I would expect that we’ll have a higher proportion of our total production from oil and liquids in 2013, even compared to the fourth quarter of 2012.

Sean McGrath

Yeah. We’re 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’re anticipating.

Craig Shere - Tuohy Brothers

Sure. And I assume since that’s significantly driven by the drill bed. Ed, you would expect that trend to continue into ‘14.

Ed Cohen

I’d say that’s the case, Craig. Yeah.

Craig Shere - Tuohy Brothers

Okay. And Ed, since I had a point on my first question after one more out there?

Ed Cohen

Go to queue.

Craig Shere - Tuohy Brothers

Okay. 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 private partnership raise. Do you see this condition having at least temporarily reversed and with this indicate the need to focus 2013 acquisitions on more high PDP properties that can rapidly be absorbed onto the balance sheet?

Ed Cohen

I think that we’re 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. So 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 our drilling operations this year as we actually did accomplish in 2012. We don’t anticipate, I don’t think anyone anticipates. The congress will be going through January 2, of 2014 where they make their termination service. You should be a lot better I think.

Craig Shere - Tuohy Brothers

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

Ed Cohen

I think each deal requires its own solutions, so I won’t want to make a general statement until we know that deal is actually our.

Craig Shere - Tuohy Brothers

Fair enough. I’ll jump back in the queue.

Ed Cohen

Okay. Thank you.

Operator

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

Praneeth Satish - Wells Fargo

Hi. Good morning. I just wanted to clarify a point on the distribution guidance for 2013. In the past, you’ve noted the range of $2.35 to $2.50 but now it seems like the language 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 $2.35 to $2.50 range?

Ed Cohen

I think we should be complemented by the attention you pay to our specific language. I think it’s a chance factor that stated little bit differently. Of course, we are still comfortable and when we say at least, $2.35 we are 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 split, specifically how much of that spending is for ARP’s own account in North Texas versus the partnership business?

Sean McGrath

It’s Sean. The budget has 145, the 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 -- when I said, Barnett, it includes the Marble Falls. So, as a remainder of that, approximately $60 million is going to go towards the partnership programs and this were the contributions we make the partnership programs to fund it.

Praneeth Satish - Wells Fargo

Okay. Great. Thank you.

Sean McGrath

No problem.

Operator

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

John Ragozzino - RBC Capital Markets

Hi. Good morning, gentlemen.

Ed Cohen

Good morning.

Sean McGrath

Good morning.

John Ragozzino - RBC Capital Markets

Can you quickly expand upon the comments you made regarding the 2013 A&D program and its comparisons to 2012? Do you expect it 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

Yeah. You just mentioned in our early comments just that the 2013 program was expected to compare favorably and I’m just wondering is that in terms of total deal size for the full year or just the attractiveness of the individual opportunities that you see basically.

Ed Cohen

I think both. We expect volume to be high and I would be very surprised 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

Okay. Thanks, Ed. With regards to the Mississippi and development programs, can you give any comments on the development of the [tyco] that you’ve seen as we’ve gotten some wells that have been online for a longer period of time? So it was really with respect to the product split and any changes in the EUR estimates?

Ed Cohen

I think Matt is being entitled to answer this one.

Matt Jones

Yeah. John, I would say that, obviously, we’ve 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 for us in the industry. We are surrounded SandRidge, Chesapeake and Midstate, and our expectation is that our wells will be very similar to and quite consistent with what others are reporting.

For our first couple wells, they continue to produce pretty nicely. We’ll add another 14, 15, 16 wells over the next three months, four months. It will still be relatively early for us, but we will have more to report in the June, July, timeframe.

John Ragozzino - RBC Capital Markets

Okay. Great. Thanks. And just one quick one. I’m sorry if I missed it. But did you mentioned, how long you guys were using, what kind of dissipation period were you using in the Utica?

Matt Jones

Yeah. We are likely to use a 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.

John Ragozzino - RBC Capital Markets

Great. Thanks. Congrats, guys.

Ed Cohen

Thank you.

Matt Jones

Thank you.

Operator

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

Wayne Cooperman - Cobalt Capital

Hey, guys. How are you?

Ed Cohen

Hi, Wayne.

Wayne Cooperman - Cobalt Capital

Did you guys give a guidance for your fundraising for this year?

Sean McGrath

Yeah. We raised at least a $150 million.

Wayne Cooperman - Cobalt Capital

Right. And have you seen something in the market that changed because, I know in the past you kind of got all this acreage now and you got all these new sales people. And I kind of what I thought you could have got to 300 or more. What’s changed in that business, why wouldn’t you go out and sell more given that tax rates are going up, not going down and interest rates are so low?

Ed Cohen

Wayne, I don’t think that anything has changed except perhaps for the better. But I think we are chastened by the federal government’s behavior during the last year and it shows us that it’s extremely hard in this climate when you have tax-oriented programs to anticipate with exactitude. But I would say, circumstances are really very favorable because as we all know, the big change is that tax rates are much higher and threatening to go yet higher. And this product should be extremely appealing this year.

Wayne Cooperman - Cobalt Capital

Yeah. When you talk to your guys, don’t you think you should be able to blowout the numbers on this or you holding it back on purpose because the economics are better to just drill them on your own?

Ed Cohen

I think that we are dealing with budgeted figures rather than anybody’s guess is to what we actually will do.

Wayne Cooperman - Cobalt Capital

I guess my question is, you are not holding back the program because you would rather just drill with their own money or are you doing that.

Ed Cohen

I think we have so much property available that we can you meet our own account needs and desires, and also have a great deal available for outside.

Wayne Cooperman - Cobalt Capital

And you were saying something about a land partnership or something.

Ed Cohen

You’ll have to go back to my comments. I don’t want to repeat it for everyone. But we really can’t go beyond what was said.

Wayne Cooperman - Cobalt Capital

And is there some filing about this with information in it.

Ed Cohen

Private placements always dictate what we can say.

Wayne Cooperman - Cobalt Capital

I guess you were asked about -- it seems like there is a lot of properties for sale but I guess the question is, if everybody else is selling, do we want to be buying the stuff that they want any more?

Ed Cohen

It’s not that they want it in many cases, but they can’t afford the whole going to it. And once again, if you bought something for $1 billion to come close to situations that we saw in close going in 2012, if you bought it for $1 billion you may not be happy with it, but if you’re buying it for a small fraction of what you spend we can be very, very happy with it?

Wayne Cooperman - Cobalt Capital

Okay. Last question, you guys, I know you, you are pretty big on hedging out gas and whatever, not taking a lot of commodity price for it, but if you sit here today and my guess is gas has done a lot of worse then you might have thought, but do you guys have a view for the next 12 months or three years or five year, and at some point do you want just increasing your commodity exposure because you think it’s going to go up?

Ed Cohen

I think our view really is optimistic especially if you go out three to five years but even in the short range. It sort of like buying insurance and it isn’t because you really think that your house is going to burn down but because it’s inappropriate way to function. Also it’s very helpful to us in terms of guarantying profit.

But you have to remember that because we are constantly increasing our actual production as a result of the acreage that we pick up that’s not developed. We have ample opportunity to profit enormously from upside without endangering the company or without endangering the buy ability the purchase we are making. So if prices rise we will get more than our share of it, feel story that the, you don’t want to be it taken the situation.

Wayne Cooperman - Cobalt Capital

Okay. Thanks.

Ed Cohen

Thank you, Wayne.

Operator

Ladies and gentlemen this concludes today’s question-and-answer session. I would now like to turn the call over to Mr. Ed Cohen for closing remarks.

Ed Cohen

Well as you can anticipate, I’m really looking forward to our next quarterly report and I’m hopeful we will have some very, very good discussions in that report. So thank you all for listening. Good-bye.

Operator

Ladies and gentlemen, we thank you for your participation in today’s conference. This concludes the presentation and you may now disconnect. Have a good day.

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