Atlas Energy's CEO Discusses Q2 2012 Results - Earnings Call Transcript

| About: Atlas Energy (ATLS)

Atlas Energy, L.P., (NYSE:ATLS)

Q2 2012 Earnings Call

August 8, 2012 9:00 am ET


Brian Begley - VP, IR

Ed Cohen - CEO

Sean McGrath - CFO

Matt Jones - President, Atlas Resource Partners

Freddie Kotek - SVP, Investment Partnership Division of the General Partner


Philip Dietz - Wells Fargo

Craig Shere - Tuohy Brothers


Good day, ladies and gentlemen, and welcome to the Second Quarter 2012 Atlas Energy and Atlas Resource Partners Earnings Conference Call. My name is Qwanda and I will be your coordinator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to 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 second quarter results. And 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 word such as "expects", "anticipates", and similar words or phrases.

Forward-looking statements, by their nature, address matters that are uncertain and are subject to certain risks and uncertainties, which can cause actual results to differ materially from those, projected in the forward-looking statements. We discuss these risks in our quarterly report on Form 10-Q and our annual report, also on Form 10-K, particularly in Item 1.

I'd also like to caution you not to place undue reliance on these forward-looking statements, which reflect management's analysis only as of the date hereof. The Company undertakes no obligations to publicly update our forward-looking statements or to publicly release the results of any revisions to forward-looking statements that may be made to reflect events or circumstances after the date hereof, or reflect the occurrence of unanticipated events.

In both our Atlas Energy and Atlas Resource earnings releases, we provide a reconciliation for 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'll be participating in several upcoming investor conferences, including the EnerCom Oil and Gas Conference in Denver on August 15th, and the Citi MLP Conference in Las Vegas in August 22nd and 23rd.

And with that, I'd like to turn the call over to our Chief Executive Officer, Ed Cohen, for his remarks on the quarter. Ed?

Ed Cohen

Thanks Brian, and hello, everyone. I'm glad to report that Atlas Energy L.P. and its MLP subsidiaries did enjoy a good second quarter. E&P production volumes at Atlas Resource Partners increased over 70% to 62.5 million cubic feet equivalent per day from only 36.6 million for the comparable 2011 period.

Gathered gas volumes at Atlas pipeline were up almost 35% year to year from 574.5 cubic feet per day to 775 million. And despite low prices for both natural gas and natural gas liquids, ATLS cash distributions at $0.25 for the quarter were 14% higher than for the corresponding 2011 period and much higher on a pro forma basis. And day ARP in its first full quarter distributed $0.40 with a 1.1 coverage ratio.

Nonetheless, this period should be seen as a mere prelude to the sharp acceleration in distributable cash flow that we anticipate in future quarters. We have taken the last months to effectuate major transformations, acquisitions, new plants, new fields, new block bluster wells, and new investor program, that are now generating and will increasingly in the near future generate substantial growth in distributable cash flow in both our downstream that is ARP, and midstream APL operations. And of course, because of its incentive distribution rights as a general partner of both ARP and APL our parent company ATLS in turn will likewise experience greatly enhanced distributable cash flow.

A major reason for our success in this low price environment has been strong hedge protection. And I might point out that in fact, we took advantage of the recent upward flip in natural gas prices to layer in yet more hedges.

At the present time, APL's projected margins and cash flow, excluding ethane, are approximately 78% protected for the second half of 2012, and approximately 75% hedged in 2013. ARP is even more heavily protected. For the full period through 2016, present production is approximately 75% hedged and entirely hedged for the second half of 2012 and the entire year 2013.

The impact of our protected polices has been quite favorable. Without financial hedging, ARP would have received at market only $2.03 per Mcf during the second quarter. With hedging, APR actually received $3.49 per Mcf, that's almost 75% above market. As a happy result, despite spot price deterioration, and all the other negative factors impacting our industry, and our national economy, ARP is still able now to reaffirm our earlier projections for the rest of 2012 and into 2013.

For the second half of 2012, we anticipate distributions at ARP of $0.90 to $1.00 and for the full year 2013, we reaffirm our earlier guidance of $2.30 to $2.45 per unit.

Beginning in the present third quarter, distributable cash flow at ARP will rise sharply as the benefits of the Carrizo and Piken acquisitions kick in, as our new Barnett division adds liquids rich new wells to be accretive existing production purchase in the second quarter, and as our new direct investment program make substantial contribution in drilling and other fees that were substantially absent in the second quarter.

Similarly, APL will begin in this quarter, and increasingly in future quarters, the benefit for the first time from the enormous investments in organic growth that we've made in three of the world's most prolific liquid rich areas, which happily are the three areas where APL is active.

Matt Jones, President of Atlas Resource Partners, and Sean McGrath, CFO, will shortly discus in detail various highlights of our second quarter, but I would like now to focus on two key matters. First, the expansion of our E&P business through strategic accretive acquisitions, and secondly, the expansion of both ARP's and APL's businesses through organic growth.

First, in the five months that ARP has existed as a public company, it has already completed three significant transactions, Carrizo, Titan, and Equal. These deals have quadrupled ARP's total net proved reserves and have been immediately highly accretive, although much of the benefit of these transactions will accrue only commencing in the current period. In a way that is on a cash basis these acquisitions have been without cost. The new assets provided the collateral for increases in ARP's bank lines in an amount more than double the cash required to complete them.

These transactions have opened the red hot Mississippi limestone area for organic development on 18,000 fresh acres, and it provided new acreage in the liquid rich sections of Barnett for further drilling, which will commence eminently.

ARP now owns some 530 billion cubic feet equivalent of total net crude reserves in the Barnett and that's up from zero, three months ago and we're far from finish. In fact, we hope to accelerate our rate of profitable growth through acquisition.

When ARP first began trading in March, we spoke about the possibility of $1 billion in accretive acquisitions during its initial year of operations. With one full quarter completed, and nearly $400 million in transactions time, ARP does seem to be on target. Some industry sources indicate that over $30 billion of divestitures will be announced in the next six months. In any case, our pipeline of prospects is quite full stay tuned.

Secondly, both APL and ARP continue to enjoy strong organic growth and success. ARP is drilling again in the Marcellus with considerable success and high anticipation. We are pursuing hot place in the Mississippi Limestone, in the Utica, and in liquids rich areas of the Barnett, on all of which Matt will surely speak.

APL has three processing complexes servicing three of the hottest areas in the world and that's not by chance. Three of the hottest areas in the world for wet natural gas, the Permian Basin in West Texas, the Mississippi Limestone in West Oklahoma and adjacent areas, and the Woodford in Southern Oklahoma. We've spent hundreds of million of dollars presently in play expanding these facilities. And so we've obtained precious first mover advantage in areas where we were already dominant, but we are only beginning to see the first cash returns from this investment. But by 2013, distributable cash flow should explode upward.

Our Velma plant in Southern Oklahoma for example for months has been producing NGLs at levels challenging the plants theoretical intake limit of 100 million cubic feet per day. To alleviate this situation, we have just completed the construction and have opened a new 60 million cubic feet per day plant at Velma built to service a long-term fee-based arrangement with a subsidiary of ExxonMobil. Sharply increased cash flow is already being realized there. The new Velma plant is already processing 45 million cubic feet per day, and should be completely full by year-end. Needless to say, we're currently planning and evaluating additional growth opportunities at Velma.

During the present quarter, our new plant at West Oklahoma wide reserves, adding 200 million cubic feet per day of capacity to a system that has had to bypass more than 100 million cubic feet per day of excess gas intake. In fact, the volume currently being bypassed represents 58% of the base load capacity of the new 200 cubit feet per day plant.

Our new driver plant in West Texas to be complete in the first quarter of 2013 and it's 200 billion cubic feet per day of capacity should go far to alleviate the excess of gas available for that facility. Within a year of opening, we anticipate full utilization of this new West Texas plant.

As I've noticed this incremental growth of APL has not yet been substantially reflected in our distributable cash flow, and even for a short period after completion, we will remain constrained on our liquids takeaway capacity in West Texas and West Oklahoma, but help is on the way.

Under firm contracts, major producers are building new takeaway lines, which should enter service shortly. By the end of the second quarter of 2013, we expect to have the capacity to maximize our liquids production, and to reach even higher record levels of cash flow. For all these reasons, I would summarize our situation as follows, quite satisfactory at present, far better in the near future.

To elaborate on that conclusion, as concerns E&P operations Matt Jones, President of Atlas Resource Partners.

Matt Jones

Thank you, Ed, and thank you all for joining our call. The end of the second quarter marks the end of Atlas Resource Partners first 100 days as a public company. During the period and leading into the third quarter, we've substantially increased and diversified companywide production in proved reserves.

We've established and expanded a new core operating area in the Barnett Shale in Texas, entered and expanded our position in the core of the Mississippi Lime play in Alfalfa, Grant and Garfield Counties in Oklahoma, expanded our targeted leasing effort in the Utica Shale, expanded our Marcellus Shale position, in Lycoming County in northeast Pennsylvania, and increased production and cash flow in our historical operating areas.

Our efforts are highly focused on our core objective of increasing the stability and growth of our cash flow on a per unit basis. Our strategy to advance this objective includes acquiring long-live producing early natural gas properties, and stabilizing the resulting cash flow streams with our hedge program, exploiting developmental well drilling opportunities associated with acquisitions, and maximizing the efficient use of our partners and our company's capital and our syndicated well drilling program by strategically expanding our inventory of favorable drilling locations in desirable areas.

As a result of the foundation that we built in consistent with our previous expectations, we expect cash generation per unit in coming quarters to increase rapidly and meaningfully. Cash flow growth per unit will result primarily from increased production, increased fee generation from our drilling activity in our partnership management segment, and to a lesser degree from increased production margins generated from a change in product mix to include more oil and natural gas liquids production, and certain efficiency gains in some of our operating areas.

Our production levels in the third quarter have increased materially compared to the second quarter. During the second quarter, and early in the third quarter, we brought online some of the best producing Marcellus wells in our company's history, some with IP rates in excess of $15 million a day and some as high as $20 million a day. The Marcellus wells were previously funded through past partnership well drilling programs.

Companywide, we're currently producing roughly 95 million cubic feet equivalents per day, which represents a significant increase compared to the second quarter average.

As we move forward through the remainder of 2012, we expect production contribution from our drilling activity in the wet gas window of the Barnett Shale, which I'll address in a moment, and from our interest in drilling activity that we're conducting in our partnership management segment. In our partnership management segment, we're actively developing our positions in the Mississippi Lime, Utica, and Marcellus, and our activity levels are greatly exceeding those of the second quarter. More on this in a moment.

Also with respect to our production margins, we've driven down production costs by better utilizing our embedded asset base, and from the addition of the Barnett producing property that generally benefit from lower production costs per Mcfe. You'll notice in our press release that we've driven down our average production cost per Mcfe to $0.71 in the second quarter compared to $1.05 per Mcfe in the year ago comparable period.

We are very excited about the substantial platform that we now control in the Barnett Shale play in Texas. Following the Titan operating company acquisition that closed in late July, our second Barnett area acquisition, we control roughly 28,000 acres of properties in the Barnett Shale, almost the entire area, which are held by production operate more than 200 producing wells and hold substantial developmental drilling locations.

Also, I'm very pleased to report that nearly the entirety of the Titan management and operating team have agreed to join our company. The Titan team led by Mark Schumacher will continue to office from their established location in Fort Worth, where they've successfully overseeing the development of the Titan Barnett Assets. The management and development of the entirety of our Barnett Shale position by the Titan team, brings skilled economies to our Texas assets, and paves the way for additional potential expansion. The addition of the Titan team will also allow us to quickly and efficiently exploit the developmental drilling locations that came to us with the Barnett acquisition, including wet gas and dry gas drilling opportunities available on existing pad sites. The acreage is largely held by production allowing for efficient and inappropriate development and abundant takeaway capacity and infrastructure already exists.

We welcome the outstanding Titan team to our company and anticipate the generation of substantial cash flows from our Barnett position for years to come. In the near-term and to ensure that our capital is directed to projects with the highest possible returns based on prevailing market conditions, we've initially focused our drilling efforts in the Barnett on our wet gas acreage.

To-date, the Barnett wet gas window, we have two wells that have been drilled to depth and are scheduled for completion later this month, and will likely be producing by the end of the third quarter. Currently with one rig running, we'll continue to drill in complete wet gas enhanced Barnett wells primarily on our Hood County acreage through the remainder of this year and into the first quarter of next year, with well connection dates scheduled throughout that timeframe.

We estimate that the capital allocated to these wells will generate significant returns and will generate highly accretive cash flows to our unit holders beginning late in the third quarter. We're currently funding our Barnett drilling directly with corporate funds.

Briefly excited about our growing Mississippi Lime position, where we now have more than 18,000 acres leased in our Alfalfa, Grant, and Garfield Counties. Again similar to the Barnett Shale position, the vast majority of the acreage is held by production and we anticipate expanding our acreage position in this very attractive oily area of the Mississippi Lime play. We focused our efforts on this area of the play as an entry point because of the anticipated quality of the geology and as a result of developed infrastructure on the acreage near to and planking our acreage position, public and private operators continue to report impressive results.

For example, SandRidge and Chesapeake, have now collectively drilled more than 530 producing horizontal wells in the play, recently announced that many of their best wells with 30 day IP rates in excess of a 1000 barrels of oil per day are located in Alfalfa and Grant Counties. Very exciting those -- for those of us with acreage concentrations in the area, because our acreage position also benefits from developed infrastructure including salt water disposal, electrical grid, and takeaway and processing capacity, we've already commenced drilling operations on our Mississippi Lime position and we expect to see initial production from our first well in the play before the end of the third quarter.

We currently have one rig running in the play and is scheduled our first 12 wells for drilling, completion, and connection throughout the remainder of 2012. All of these wells are scheduled for inclusion in our partnership drilling programs.

In Appalachia, we continue to lever our longstanding and successful operating history and significant presence in the region. On our Marcellus Shale acreage located in Lycoming County in northeastern Pennsylvania, I'm happy to report that we drilled our first well to depth on the pad site that will include a total of five wells.

We moved the rig for the second location on the pad and planned to have all five wells drilled and completed by the end of the year. These wells will also be included in the partnership drilling program.

Our acreage in Lycoming County is close to some of the most prolific natural gas wells in the United States and we're very excited about the prospects for this area and the many potential drilling locations that we hold.

In a year to comply on our Harrison County, Ohio acreage, we're scheduled to initiate well drilling activity in September on three wells from a single pad sight and these wells will be included in our partnership drilling program. Our Harrison County acreage is in close proximity to Chesapeake's Energy Buell Well and is in the midst of the area of activity where the great majority of permitting and drilling activity is ongoing in the Utica shale. The Buell Well is the most productive well. It has been drilled and reported in the Utica formation to-date.

Also we've recently and strategically expanded our acreage position perspective for the Utica point present, primarily through the acquisition of a contiguous acreage position located in Tuscarawas County. This acreage adds meaningfully to our very attractive future well sights in the Utica play.

In total, we've materially increased our production through acquisitions and through the exploitation of high quality drilling locations and expect to see rapid expansion of our cash flow in upcoming quarters.

We expect to accelerate these efforts moving forward and to remain focused on our primary objective and that is to add stability in growth to our cash flow per unit.

This concludes my remarks and I'll turn the call to our CFO, Sean McGrath.

Sean McGrath

Thank you, Matt, and thank all of you for joining us on the call this morning. First regarding ARP, we generated adjusted EBIDTA of $16.6 million or $0.50 per unit, and distributable cash flow of $14.3 million or $0.43 per unit for the second quarter of 2012.

We distributed $0.40 for one of the partnering unit for the period based on these results, representing 1.1 times coverage ratio.

Production margin for the period of $18.9 million or $3.32 per Mcfe represented an almost 50% increase compared with $12.7 million for the first quarter of 2012.

The second quarter saw volumes from out initial Barnett acquisition and on it's 10% increase in Appalachia production volume from the first quarter due to significant contributions form 12 of our 16 legacy, southwest and Pennsylvania, Marcellus horizontal wells connected during the period.

The remaining four legacy Marcellus wells returned in line during early July, which when combined with the additional production from the same acquisition, will yield significant overall growth in production volumes for the third quarter of 2012.

While spot gas prices covered around $2.00 per Mcfe for the majority of the second quarter, we were protected on almost 100% on our natural gas production, in excess of $3.50 per Mcf due to our significant hedge position.

Lease operating expenses for the period of $0.71 per Mcfe were over 30% lower compared with the first quarter of 2012, through low cost Barnett production and the higher Appalachia production volumes drove cost per Mcfe significantly downwards. But the addition of the equally low cost tightened Barnett production coming online during the third quarter 2012, as well as the connection of these additional four southwestern Marcellus horizontal wells, we expect our overall lease operating expenses per Mcfe to continue to move significantly lower in future periods.

Partnership management margin for the period was approximately 5.8 million, 30% decrease from the first quarter 2012, as our 2011 partnership programs have a majority of there capital deployed during the first quarter, and the new partnership programs and I guess started out as we worked successfully through the diligent process to initiate the program.

We estimate partnership management margin to be in excess of $9 million for the third quarter of 2012. As a remainder we recognize, well drilling and completion revenue as we invest our drilling partner's capital, and administrative and oversight revenues when drilling program wells are spud.

During the current quarter, we deployed $12 million of our joint partners' capital with an additional $19 million of funds raised that remain to be deployed at period end, the majority of which we expect to deploy during the next six months.

Moving on to general and administrative expense, net cash G&A was $8.8 million for the period, which represented a 6% decrease from $9.4 million for the first quarter 2012, a certain seasonal cost including year-end compliance work and cost incurred to build our technical fit moderated between peers.

Gross capital expenditures for the period were $25 million compared with $17 million for the first quarter of 2012. The increase between periods was principally due to $15 million increase in lease acquisition cost, as we continue to enhance our already attractive acreage position in Mississippi Lime, Marcellus shale, and Utica shale. This increase was partially offset by $9 million decrease in capital contributions for the partnership program due to the timing of capital deployed.

With regard to risk management activity, our strategy is significantly mitigating potential downside to commodity volatility, which clearly embodies in our Barnett Shale acquisition, in which we had an average of 90% of available production for the initial 12 months of production, 80% for the following 24 months, and 40% for the remaining 24 months, with additional production expected to be put on in the outer years in the near-term.

Our effective average core price for the first five years of these acquisitions covering almost 40 billion cubic feet of production is approximately $3.50 per Mcf, which offers ARP attractive economics for both transactions.

Overall, inclusive of hedges for the Barnett acquisition, we've hedged positions covering almost 80 billion cubic feet of natural gas production at an average floor price of almost $4.20 per Mcf for the period through 2016, consisting of a combination of put, swap, and collars, to provide us with downside protection but upside potential in this low natural gas price environment.

In addition, we've hedged in average of over 70% of our current run rate crude oil production for the next four years and an effective average floor price in excess of $9 per barrel.

As we executed our hedged strategy during the period, we rebounced certain hedged positions we had for 2015 and '16, which resulted in an additional hedge positions for 2015, as well as 3.8 million of net proceeds from amortization.

We're 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 had demonstrated in the past. Please see the tables within our press release for more information about our hedges.

Moving on to our deposition and liquidity. In connection with the Barnett acquisition, we expanded our Barnett base by almost 25% to $310 million, which was heavily oversubscribed in syndication. Pro forma for the recent same acquisition, we've approximately $165 million of available capacity under the revolver, which provides us with ample liquidity.

With regard to our Atlas Energy, L.P., we distributed, we generated distributable cash flow of $12.2 million and distributed $0.25 per unit for the period, representing a one-time coverage ratio. Going forward, we expect ATLS to maintain minimum coverage on its cash distributions, as ARP and APL both expect to maintain ample coverage ratios in the future periods.

Atlas Energy Bcf included $5.4 million of cash distributions from APL, including $1.6 million from incentive distribution rates, representing a 50% increase from the prior year second quarter, as APL significantly grew it's cash flow over the last 12 months.

Atlas Energy Bcf for the period also included $8.6 million of cash distributions from ARP.

Cash G&A expense for Atlas Energy on a standalone basis was $2.1 million for the period, compared with $2.5 million for the first quarter of 2012. Cash G&A expense for the current period reflected a number of seasonal expenses including, annual shareholder meeting and compliance costs, which will moderate in future quarters.

Going forward, we expect ATLS's G&A expense be approximately $1.5 million to $1.7 million per quarter for the remainder of 2012.

Finally, I would like to quickly mention ATLS's strong standalone balance sheet, which has no debt outstanding on its $50 million credit facility.

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

Ed Cohen

Thanks Sean. And Qwanda, we're now ready for questions.

Question-and-Answer Session


Thank you. (Operator Instructions) Your first question comes from the line of Philip Dietz with Wells Fargo. Please proceed.

Philip Dietz - Wells Fargo

Just couple of questions. First, could you just provide an update on how much capital you expect to deploy in the partnership program this year, is it still around $190 million?

Ed Cohen

You know it's always unpredictable, but I'd say that's a reasonable number. We're hopeful that we will do even better than that.

Philip Dietz - Wells Fargo

Okay. And can you talk about just overall demand on the fundraising side, as we look to 2013, is it fair to assume that fundraising will be at least as high as 2012 in that $250 million range?

Ed Cohen

Actually our Director of Fundraising is here so perhaps he will answer that.

Brian Begley

We're the private placement on the street right now we can't comment on fundraising, as it will have an effect on the market. So we're under a sort of blackout provision until the fundraising closes so, I really can't comment.

Philip Dietz - Wells Fargo

Okay. Fair enough. Just last question, in terms of capital deployment over the balance of the year in the partnership program just wondering if you could give a rough breakout as to how much will be spent in the Marcellus versus Utica versus Mississippi Lime?

Ed Cohen

Freddie, you want to answer that Freddie.

Freddie Kotek

Yes, first of all in the Marcellus we're drilling five wells currently and we will complete those wells this year. Those wells have AFE, call it roughly $7 million. So those wells will be largely funded this year. In the Mississippi Lime, we're progressing with drilling, I mentioned in my comments that we will have our first Mississippi well online in the third quarter, but we're progressing in Mississippi Lime with drilling development on our first 12 wells there. Well cost there we estimated going to average call it roughly $3.5 million give or take. In the Mississippi Lime, progression in terms of capital invested this year the progression of those wells I would estimate something like half to two-thirds of the capital per well will be invested this year in 2012. And then in the Utica, we're spudding three wells later in this quarter and late September, we're spudding all those wells on a single pad site by the way which will be quite efficient, relative to one of their operators who are doing right now. But we will spud three wells in September; we will begin drilling in completion efforts on those wells probably complete drilling this year begin completion effort on those wells this year and into early next year so. Those wells we estimate it will cost somewhere around $7 million a well also, and I would suggest that again probably may be 60% to 70% of that capital per well would be expanded this year. So these are rough numbers haven't given you the totals but you can derive totals I think from what I've told you.


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

Craig Shere - Tuohy Brothers

Hi guys. Congratulations on the progression of things from here sure forward it sounds like this could be a nice uptick into 2013.

Ed Cohen

Thanks, Craig.

Craig Shere - Tuohy Brothers

Couple of follow-ups here, understand during a blackout period on your partnership race currently, but you gave ARP guidance for distributions in the 2013 previously after announcing the second Barnett Titan acquisition and I wanted to confirm that guidance in the 2013, assumed simply flat year-over-year partnership rates?

Ed Cohen

We're making no exciting assumptions about partnership race. And so I think your assumption is a safe one to work from.

Craig Shere - Tuohy Brothers

Okay. And now Sean, the $1.5 million to $1.7 million cash G&A in the second half was that for the full second half or per quarter?

Sean McGrath

Oh per quarter, it's per quarter, yeah. In this quarter we just saw a little bit just timing of expenses and we would expect to moderate per quarter for the remainder of the year and be around that rate kind of going forward on a rolling 12 month basis.

Craig Shere - Tuohy Brothers

Okay. So that's a good ongoing rate. And I think you said that Marcellus production was up 10% sequentially, how much was that on an absolute basis?

Sean McGrath

It was about $3.5 million a day. Are you talking about in terms of the volume just for the Appalachia?

Craig Shere - Tuohy Brothers


Sean McGrath

Yeah, it's about $3.5 million a day.

Craig Shere - Tuohy Brothers

Okay, great.

Ed Cohen

Craig if I could just add to that, we also added some Marcellus horizontal wells in July in the third quarter, so you will see an uptick again in the July month and in the third quarter with Marcellus production.

Craig Shere - Tuohy Brothers

Great. And now I think you were saying that we will have third quarter Mississippian wells online or are you going to wait for the third quarter call or may be put out any press releases about the results there?

Ed Cohen

We're pretty -- we're very excited about what's occurring in the Mississippi Lime for us and I did say Craig that we will likely have first production from our first Mississippi Lime well in late September. The -- one thing I will say, we expect great results from all of our wells, but I think many producers will tell you especially those that have drilled many wells now in Mississippi Lime that it is a statistical play. We have on our acreage currently; probably something in excess of 100 drilling sites and that assumes three wells per section. Some producers are suggesting that four wells per section will be more efficient development plan for acreage in the Mississippi Lime. But we will bring on our first well in late September. We're likely to bring on another well in October perhaps one or two in October/November. So, we should have several wells we hope producing by our next earnings call and that would probably a logical time to discuss those results.

Craig Shere - Tuohy Brothers

Great. And what is -- I'm sorry if I missed it, did you mention the size, the Utica acreage at this point?

Ed Cohen

Our Utica position I didn't, I did mention that we just added a very nice parcel and clearly in the wet gas and oily window of the Marcellus and Tuscarawas County is just out of the Stark County, Tuscarawas County. In Tuscarawas County just south of Stark County. But we, in that part, so we have something like 2400, 2500 acres that are contiguous the property lines are perfectly really for development with relatively long lateral lines per well. We think we can fit as many as 20 or more Utica wells. We held very productive Utica wells on that property. Clearly in terms of the total acreage in the Utica today, we're probably somewhere around 4000 acres give or take.

Craig Shere - Tuohy Brothers

Okay. And you sound a little more excited about this latest block that may be a little more comfortable from a contiguous nature for drilling. Are there opportunities to swap acreage to get a nice block that you can think introduce into?

Ed Cohen

Right, we're very excited about our Harrison County acreage. We're drilling wells -- we'll start drilling wells in September. The Tuscarawas acreage benefits from being a larger position and we will drill more wells on that acreage, there may be opportunities. We do have some smaller parcels in some equally desirable areas that could end up being positions that we could swap out to increase contiguous positions that we control today, that's possible.

Craig Shere - Tuohy Brothers

Okay, great. And I noticed and I'm sure this has to do with commodity prices, which none of us has any control over, but despite an all equity $180 million tightened deal, the revolver only increased $60 million between cash-on-hand, which may include some summer raise funds that have yet to be deployed and your revolver capacity may be you'd have the ability -- at the limits of finance the next acquisition it's in the same $180 million, $190 million category without third-party equity. I guess my question is given the slow rate of increase relative to your acquisitions of the revolver, do you feel you could rapidly access that on the shale filings and high yield debt to avoid tapping third-party equity with the next deal?

Ed Cohen

Well, I think you've hit it right on the head. We've maximum flexibility. We look at each deal. We figure the best way to do it and it obviously will not be impossible for us to do substantial and perhaps even very substantial acquisitions without having the issue whereas substantial additional equity. On the other hand, we look at each situation and determine just how to handle it. But we certainly are in a great position right now with so much dry powder and with so many deals circulating, as you all know from in the public sector from announcements that other companies have made, we're in a very desirable situation. That's why I really look forward to the next call.

Matt Jones

Great. Just to add on that too, one thing that may be I just point out is that -- with the acquisitions we've been targeting with the PDPs we're acquiring, normally we'll increase our borrowing base by a substantial amount of the PDPs we're acquiring. So, while it seems like we had that much capacity if we do it, we're just saying for example $200 million acquisition with a large amount of PDPs. We would expect to get a substantial increase in the amount of bill basically under a revolver so we could still finance under revolver, not that we obtain we would do it in that fashion, we would also as the same look at the optionality otherwise finance it based on the specific characteristics of the acquisition, but we would have more capacity on the revolver to do that.

Craig Shere - Tuohy Brothers

Sure, but this latest increase is after Titan, right?

Matt Jones

Right. The 310 that we did another acquisition, but we usually every time between signing and close, we would go out for our bank group and say hey, these are the PDPs we're acquiring. What would be -- we would expect x amount of increase in our revolver upon closing that acquisition and could use the availability, the expanded availability under that revolver to fund the transaction.

Ed Cohen

It's a beautiful situation, the more you spend, the more you receive and of course one of the nice things is you've got the collateral and at the present time the banks are lending in very straightened fashion, so that if prices return to something more normal we may actually do, I won't call it a hat trick but the very desirable situation that perhaps at some time in the future we'll find that we actually generated more cash on our bank line from the collateral than we spend acquiring at these low, low prices.

Craig Shere - Tuohy Brothers

Sure it's certainly doesn't hurt that and that gas prices are finally turning the right way?

Ed Cohen

Absolutely, absolutely.

Craig Shere - Tuohy Brothers

So if you could provide any additional color update on where you're kind of focusing your interest in ongoing transactions on the E&P side and may be the deal size. Are there a lot still in that $200 million category or you're looking at $500 million plus with any seriousness right now and are we just focused on, not that you don't have a small number of great plays but the existing plays in Marcellus, Utica, Mississippi, and Barnett, is this really where you want to focus your attention going forward?

Ed Cohen

Craig, we did try to answer the question with various presentation. This is Ed speaking. However the past is always a good guide to the future and the transactions we've done we're very satisfied with. At APL the growth has been entirely organic. We've not done an acquisition of substantial size and perhaps the way just five years or so. It's asystematic that larger deals are usually easier to do than smaller deals. We were in a startup situation. So we are very proud of what we've accomplished. But I would not roll out our looking at deals that have characteristics different than the ones we've been doing in the last few months.

Again I direct everyone to the public press, that there are a lot of major companies who did not hedge as wisely as we did or perhaps other factors came into play. But there does seems to be a lot that's available and so you can draw your own conclusion based on our past record as to where we're likely to be. Our company motto you may remember is more of the same, but over the years of the new Atlas and the old Atlas we've done all kinds of deals and I think it's safe to assume that we will roll out doing all kinds of deals in the future. And so opportunistic we want to do deals that bring people to their feet cheering with happiness with what we've done and I think we've gotten that kind of response from some of our prior deals. So, rather than size, I think we concentrate on the positive aspects of each transaction.

Craig Shere - Tuohy Brothers

Great. And last question and this time, deals with M&A, but also the kind of operating and partnership management side. How do you decide what wells -- I mean, the latest liquids-rich Barnett while if I guess are going or not going in the partnerships? But from the more expensive maybe $7 million plus price tags wells in other areas are, how do you decide the mix there in terms of the amount of liquids, the cost of the well, and what's going to entice successful capital raises in future?

Ed Cohen

I think a major criterion that we follow is certainty of result. All right, the direct investor programs we feel are very heavy fiduciary obligation concern. And we don't feel that those are programs, which are appropriate to experimentation, no matter how confident we may be in the high success that we feel is likely. So, I think that's a major criterion and it cuts across all aspects.

Craig Shere - Tuohy Brothers

So, for example, in the Barnett is, as you successfully drill up the few wells on your own incline then at some point in the future, it might be appropriate for the partnerships?

Ed Cohen

Well, that seems reasonable though hypothetical.


(Operator Instructions)

At this time, I would now like to turn the conference over to Mr. Ed Cohen for closing remarks.

Ed Cohen

My closing remarks, I really look to the future as I think this call did. I'm really looking forward to, as I indicated, to our very next call because I think we set the framework and now the fruits should begin to fall into our mouths and laps. Thank you.


Thank you for joining today's conference. That concludes the presentation. You may now disconnect. And have a great day.

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