Atlas Resource Partners' CEO Discusses Q3 2013 Results - Earnings Call Transcript

Nov. 8.13 | About: Atlas Resource (ARP)

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

Q3 2013 Earnings Call

November 8, 2013, 9:00 AM ET


Edward Cohen - Chairman of the Board and Chief Executive Officer

Matthew Jones - President

Mark Schumacher - Chief Operating Officer

Sean McGrath - Chief Financial Officer


Stephen Maresca - Morgan Stanley

Praneeth Satish - Wells Fargo

John Ragozzino - RBC Capital Markets

Michael Peterson - MLV & Co.

Abhi Sinha - Wunderlich Securities


Good day, ladies and gentleman, and welcome to the Q3 2013 Atlas Energy L.P. and Atlas Resource Partners L.P. Q3 earnings conference call. My name is Sharon, and I will be your operator today. (Operator Instructions) I would now like to turn the call over to Brian Begley, Vice President, Investor Relations. Please proceed, sir.

Brian Begley

Good morning, everyone, and thank you for joining us for today's call to discuss our third quarter results. As we get started, I'd like to remind, everyone, that during this call we'll make certain forward-looking statements, and in this context forward-looking statements often address our expected future business and financial performance, and financial condition and often contain words such as expects, anticipates and similar words or phrases.

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

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 result 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 our anticipated events.

In both our Atlas Energy and Atlas Resource earnings releases, we provide a GAAP reconciliation of the non-GAAP measures that we refer to in our public disclosures. And lastly, we'll be participating in several upcoming investor conferences, including the Stephens Capital Conference, on November 12; the RBC MLP Conference in Dallas, on November 21 and 22; and the Wells Fargo Energy Conference in New York, on December 10.

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

Edward Cohen

Thank you, and hello, everyone. Let me be direct. There's been a lot of static over the past few months. Short-seller attacks, when other companies in the energy business, some weakness in oil prices, natural disasters and delays and third-party infrastructure completion. But none of this should obfuscate the simple truth of the past quarter for Atlas Resources, ARP, and for its parent company, Atlas Energy, ATLS, and that truth is a good company is getting ever better and the facts demonstrate this.

At ATLS, cash distributions increased to $0.46 per unit for the three months ended September 30, 2013. That's an increase of about 70% over the corresponding 2012 period and 4.5% above the second quarter 2013. At ARP, the third quarter distribution of $0.56 per limited partner unit represents a 30% increase from that of the prior year period and an approximate 4% increase over the second quarter 2013, and that's on approximately a 1.1x distribution coverage for the period.

It's well known I think that these increases reflect favorable trends at both ARP and at Atlas Pipeline Partners, APL, Atlas Energy's principal subsidiaries. APL is now moving and/or processing over 1.5 billion cubic feet of gas and liquids per day, approximately three times the volume handle only two years ago. Distributions have risen accordingly and massive additional organic projects are underway and in preparation.

And I know that many of you are expectantly aware of the impending activation of Atlas Growth Partners, ATLS' newest subsidiary and we hope and expect a third arrow in our quiver. But ATLS does have yet other assets that are sometimes overlooked. For example, just two days ago, the world was reminded of the dynamic growth of yet another ATLS resource, Lightfoot Capital Partners L.P., a private partnership of which ATLS owns an approximately 16% interest in Lightfoot's general partner as well as an approximate 12% limited partner interest in Lightfoot itself.

Now on November 6, two days ago, as I said, Arc Logistics Partners LP, a master limited partnership involved in storage, throughput and transloading of petroleum products. Arc Logistics effectuated a public offering with initial market capitalization of approximately $250 million. Lightfoot owns 100% of the general partner of Arc and retains ownership of 43% of ARC's limited partnership units.

Closer to home, ARP likewise has enjoyed a fine quarter. We've already mentioned the substantial increase in Atlas Resource distributions to unitholders. Underlying the distribution increases, average net production for the third quarter 2013 reached a record 261.4 million cubic feet equivalent per day. That's a 96% increase from the prior quarter, an increase fueled primarily by newly acquired wells in Raton and Black Warrior Basins of New Mexico and Alabama, respectively. These new assets in fact have been producing at levels in excess of those we projected at the time of acquisition and have been doing so with low production cost and low decline profiles.

ARP's newly drilled Marcellus Shale wells continue to produce at remarkably high levels. Despite, third-party and other infrastructure limitations that should be ameliorated in the near future. These blockbuster wells located in Lycoming County, Pennsylvania, contributed only marginally to third quarter results, because of their inauguration late in that period and at a time of distressed price levels. Prices have now improved sharply, while production amazingly has not declined at all, attributed to the power of these gargantuan assets.

Also late in the third quarter, ARP began connecting wells drilled in the Utica-Point Pleasant formation the northern Harrison County, Ohio. Here too results have been even better than our strong initial expectations. We are especially happy with the levels of high grade condensate. However, we are not yet enjoying the full benefit of these extraordinary wells, because the production disruption is related to Natrium plant fire, which occurred in late September 2013. ARP however, has been successful in finding some alternative processing outlet and is in the process of identifying yet additional third-party capacity, which will enable us to optimize production.

Turning to Texas, ARP has now drilled over 40 wells this year in the oil and liquids rich Marble Falls play. Primarily, in Jack County, Texas, where the company holds mineral rights to approximately 75,000 net acres. ARP has now identified additional productive zones, located above and below the Marble Falls play, including the Caddo formation, Bend conglomerates and Chappel Reefs. Early testing of these formations have yielded initial production rates of 100 to 300 barrels of oil per day. Additional 3D seismic is being undertaken to further develop these formations in conjunction with the Marble Falls.

Our Mississippi Lime production is a further source of satisfaction. Wells completed in the third quarter have performed substantially above our predictions prior to drilling and completion, and these earlier expectations, let me tell you, we're far from pessimistic. Wells connected in the third quarter produced on average 468 barrels of oil equivalent per day. And that was composed of 53% liquids, including a 161 barrels a day of crude oil and 46% residue gas, more than 50% above volume expectations and to the higher ratio of liquids to residue gas.

Matt Jones, President of ARP, is sitting next to me, salivating to give you more information on the Mississippi Lime success and on the quarter's other happy results in the field. Matt?

Matthew Jones

Thank you, Ed. First, just wanted to welcome Mark Schumacher to our call today. Mark Schumacher is Chief Operating Officer, and Mark will be available to assist in answering questions at the end of the call.

But with respect to where we have been and where we're going, I want mention that since March of 2012, when ARP began trading as a public company, we provided to our common unitholders a peer leading cash distribution growth rate of roughly 40%.

Our track record results from a number of factors, including the effective acquisition and assimilation of high quality producing assets, the exploitation of liquids rich and high yielding dry gas drilling locations, the generation of increasing cash fees through the management of our drilling investment programs and the dedication and talent of our employees.

Our recent acquisition of mature long-life and low-decline assets on the Raton and Black Warrior Basins are producing at levels exceeding those expected at the time of acquisition, and have contributed to ARP's record gross production of 533 million cubic feet equivalents per day and a peak net production rate of 275 million cubic feet equivalents per day in the third quarter.

Of course, in today's oil and gas world, the term equivalent has become a misnomer to a degree, because of the substantial price separation between natural gas and liquids production. On that front, we increased oil production in the third quarter to roughly 1,520 barrels per day compared to an average of 1,280 barrels per day in the second quarter, a sequential quarterly increase of nearly 20%. We also increased NGL volumes to roughly 3,730 barrels per day from our 3,380 barrels per day in the second quarter, a sequential quarterly increase of about 10%.

We achieve record levels of production and quarter-to-quarter increases, despite only limited contribution from our recently connected and high rate Marcellus gas wells in Lycoming County in northeastern Pennsylvania and from our recently completed liquids rich Utica wells in Harrison County, Ohio.

In the Marcellus, we began connecting to production. Eight wells we have developed on our Lycoming County acreage in August. After the clean-up period and as we had referenced in ARP's operations update press release several weeks ago, these highly productive wells reached the total gross daily production rate of 62 million cubic feet per day during September, which maximized the available infrastructure. Of course, we only had the benefit of this production for a short period of time during the third quarter.

As Ed had mentioned, our Marcellus Lycoming wells continue to produce at a rate of 62 million cubic feet per day collectively through the month of October and continue to produce at that rate based on our recent November reports. So we've experienced zero declines so far from our Lycoming Marcellus wells. And we expect production here to remain at or near these levels for the remainder of the fourth quarter, perhaps longer.

Of equal or greater importance, the negative differentials in northeastern Pennsylvania had a specific impact to our company, the Leidy pricing differential have significantly abated. For example, over the last 15 days or so the Leidy pricing differential has averaged at about $0.60 compared to rates three times at higher or more during September and into early October. It's worth noting that the Leidy pricing differential averaged $0.13.

In the second quarter, the four pipeline expansion projects in northeastern Pennsylvania caused significant reduction in throughput capacity in an unusually cool late July and August period, caused power generation demand to drop by more than 20%. As recently as this morning, Leidy pricing continues to recover trading at roughly $0.40 differential, so the Leidy pricing recovery continues.

Also in September, we initiated clean-up and flow-back on five Utica-Point Pleasant wells in Harrison County, Ohio. As we were cleaning up our wells one of the key processing plants available to Utica producers caught fire and was temporarily shut down causing a temporary loss of processing capacity in the region. As a result, we recorded a very limited amount of production from the Harrison County wells in the third quarter.

Beginning in early October we were able to gain access to limited processing capacity and continued the clean-up process on the wells, notwithstanding the significant production limitations. In October, we produced nearly 18,000 gross barrels of high-grade condensate in total or almost 600 barrels per day, all this from restricted flow rates on two of the five wells on average.

The gas-to-oil ratio was roughly 275 barrels per million cubic feet of wet gas, a very significant level especially considering the quality of the condensate, with an API gravity level of about 55 degrees. We've received pricing of NYMEX of roughly $6 per barrel for the Utica high-grade condensate.

We continue to work to find greater processing capacity for all of our wells in the very near-term. Over the course of the fourth quarter and into the first quarter of next year, newly build processing capacities coming online, and additionally we and the industry anticipate in January the return-to-service of the plant that experienced the fire disruption in mid-September.

Moving to our Texas operation. The contributing factor to our liquids production increased in the third quarter was the continued success of our liquids rich Marble Falls drilling activity. We have two rigs running on our Marble Falls acreage and we drilled, completed and connected 17 gross and 10 net wells at various intervals throughout the quarter. Our current Marble Falls drilling activity is scheduled to be partially funded through our drilling investment program and partially from ARP's cash resources.

Our expectations for 175,000 plus acres and hundreds of drilling locations in this oil rich play continue to expand as we've identified additional productive zones on our acreage. Our vertical drilling program allows us to complete multiple zones and seek stack pay opportunities including the Marble Falls, Barnett Shell and more recently identified pay zones including the Caddo, Bend conglomerates and Chappel Reef.

And exciting recent example of this stack pay opportunity on our acreage includes a recent well where we completed the Caddo section based on 3D seismic and petrophysical log interpretation. In this case, for the incremental cost of roughly $30,000, we stimulated the Caddo formation and began producing solely from that section several weeks ago.

Again, only producing from Caddo section, we produced about 3,630 barrels of crude oil or 182 barrels per day for the first 20 days of production. Roughly speaking and producing only from the Caddo zone, we paid back more than 40% of the well cost in 20 days and haven't yet begun producing from the Marble Falls and Barnett zones. Needless to say, we have an initiative in place to thoroughly review our 3D seismic data to find additional stack pay opportunities across our acreage.

Our asset teams believes that we also have a meaningful opportunity to re-complete various stack pay zones that weren't exploited in the past by previous operators on wells that we have inherited when we acquired our Marble Falls position in late 2012. We'll likely attack some of these re-completion opportunities beginning in early 2014.

The two rigs running in the fourth quarter, we expect to drill and complete 28 gross wells and 14 net wells with many of those scheduled for connections through the course of November and December. Also, on our Marble Falls property, we're investing in the extension of our water gathering disposal infrastructure to enhance the efficiency of our operations and reduce operating costs.

The disposition of produced waters across is a single largest component of our operating expenses in the Marble Falls and we focused our efforts on reducing these costs. The added infrastructure allows to significantly reduce water hauling and trucking costs in those areas where we have producing wells and perspective drilling locations, not currently served by our existing infrastructure.

We expect the added infrastructure to begin to benefit our operations in the first quarter of next year. We're also expanding our water disposal capacity on our Mississippi Lime position.

We're adding a third salt water disposal well to our Mis Lime infrastructure and we expect the well to be functioning in December. We anticipate that the additional water disposal capacity will allow for more efficient distribution and produce water across our acreage, enhancing production from existing wells and will accommodate forthcoming production for well drilling activity anticipated for later this year and into 2014.

From a production point of view, our Mis Lime activity also contributed to ARP's growth in liquids production during the third quarter. We connected five Mis Lime wells during the quarter and we now have at least 45 days of production history for each of the wells.

On average, over the 45 day period, as Ed mentioned, the wells connected in the third quarter produced 468 BOE per day, composed of 53% liquids, including 161 barrels a day of crude oil and 46% residue gas. This compares to a tight curve for a 45 day period of roughly 290 BOE, composed 58% of liquids, including 126 barrels of oil per day and 42% residue gas.

With two rigs currently running on our Mis Lime position, we expect to connect five additional wells in the Mis Lime in the fourth quarter. All of our current well drilling activity in the Mis Lime is scheduled for inclusion in our 2013 drilling investment program.

Our drilling program remains diverse and highly concentrated in oil and liquids rich areas. It is our belief that our focus on exploiting our liquids enhanced drilling location, allows us to efficiently replace natural declines in our producing assets and provides an attractive core well prospects for our company and for those who invest in our drilling program offerings.

We're focused on improving the efficiency of our operations, reducing well cost and preparing our company for future stages of growth. The ultimate objective remains at the core of all that we do and that is to provide a stable and growing cash flow stream for the benefit of our investors and to build value across our company.

That concludes my remarks. And I'll turn the call over to our CFO, Sean McGrath.

Sean McGrath

Thank you, Matt, and thanks all of you for joining us on the call this morning. First, regarding ARP, we generated adjusted EBITDA of approximately $61 million or $0.89 per unit and distributable cash flow of $42 million or $0.59 per unit for the third quarter of 2013. ARP distributed $0.56 per limited partner unit for the period based upon these results, representing a 1.1x coverage ratio for the quarter as well as on a rolling four quarter basis.

I'd like to take a quick moment to mention that we have made extensive adjustments to our presentation of adjusted EBITDA and DCF, and the components of such amounts in our earnings release, including segregating certain amounts into discretionary adjustments considered by the Board of Directors of ARP's general partner. These changes reflect our effort to provide investors with a full understanding of the way we view ARP's business.

Production margin for the third quarter of approximately $58 million represent a 7% increase compared with the $54 million for the second quarter of 2013, and an almost 200% increase compared with the $20 million for the prior year third quarter. Excluding the $22 million margin contributed by the newly acquired EP Energy assets, legacy production margin of almost $36 million, represent a 28% increase from sequential quarter, which is principally the result of an approximate 10% increase in total legacy production volume to $146 million of equivalents per day, including an approximate 20% increase in oil volumes.

The volumetric increase is driven by the connection of wells in our focused areas, as Matt mentioned earlier, including the Marble Falls, Mississippi Lime and Marcellus Shale. We expect the fourth quarter of 2013 to benefit from a full quarters production from these wells as well as a number of additional wells scheduled to be connected.

With regard to commodity prices, although NYMEX gas prices were approximately $0.55 lower in the third quarter of 2013 compared with the sequential quarter, realized gas prices were $0.15 higher due to higher hedge prices. In addition, realized oil and NGL prices increased 2% and 10% respectively from the second and third quarter to over $92 per barrel and $0.69 per gallon.

Lease operating expenses for the period of $1.15 per Mcfe were approximately 5% lower than the second quarter of 2013, due to the inclusion of the low cost Raton and Black Warrior production from the date of acquisition as well as a decrease and recompletion of workover cost, which occurred in the second quarter.

Partnership management margin for the quarter was over $13 million, which is over $4 million higher than the second quarter of 2013. This amount includes $4.8 million of well construction and completion margin that we earned under the partnership agreement through the deployment of capital on partnership wells and recognized within our distributable cash flow. Although GAAP requires us to differ recognition within net incomes for the fourth quarter due to the timing of partnership fund flows.

Moving on to general and administrative expense. Net cash G&A was $9.5 million for the period, which was consistent with the prior year third quarter and approximately $1 million higher than the second quarter of 2013. The increase from the sequential quarter was due to slightly higher personnel cost, principally related to additional staff associated with the EP Energy acquisition and the timing of other administrative cost. We expect cash G&A expenses to moderate during the fourth quarter of 2013 in comparison to the current period.

Total capital expenditures were approximately $74 million for the third quarter of 2013. This included $29 million of CapEx for direct well drilling in the Marble Falls and Mississippi Lime regions and $28 million of investments in our partnership programs, which is higher than forecasted due to the timing of partnership fund flow, as mentioned previously.

As I mentioned earlier, we experienced significant increase in production margins from our deployment of capital during the third quarter and expect them to continue to have a positive impact in quarters to come.

With regard to maintenance capital expenditures, as I mentioned on the prior quarter's call, we've recognized maintenance capital expenditures in a manner, so as to stem the decline in production margin and cash flow in future periods due to natural declines in production.

We believe this methodology would be the most accurate manner to calculate maintenance CapEx and enhance the sustainability of our cash distribution. We calculate this decline in production margin by multiplying our forecasted full year production margin by our expected aggregate production decline of PDP wells, which is currently forecasted to be in 11% to 13% range.

Our maintenance CapEx has been based upon the cost of a blend of wells we expect to drill that will generate an estimated first year margin equivalent to that production margin decline. Just to be clear, the blended wells utilized in this calculation includes drilling in the Marcellus and Utica Shale, Mississippi Lime and the Marble Falls.

We provided additional details with regard to these assumptions utilized in this calculation in the footnotes of our earnings release. Utilizing this methodology, we estimate maintenance capital expenditures to be between $10 million and $12 million for the fourth quarter of 2013 and to be between $45 million and $50 million for 2014.

With regard to risk management activities, we continue to execute our strategy of methodically yet opportunistically, mitigating potential downside commodity volatility for both our legacy and acquired production.

Overall, we have hedge positions covering approximately 207 billion cubic feet of natural gas production at an average floor price of over $4.25 per Mcf for periods through 2018. In addition, we have hedged an average of approximately 100% of our current run rate crude oil production through 2015 at an effective average floor price of approximately $90 per barrel with additional hedges through 2017.

As a reminder, 100% of our commodity derivatives are swaps and collars, which simply provide us protection against commodity price movements. We are committed to add protection to our business by 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 table's within our press release for more information about our hedges.

Moving on to our liquidity position and leverage. At the end of September, we had approximately $410 million of availability under our $835 million revolving credit facility, with a leverage ratio of approximately 4.2x, which we expect to the decline to comfortably below 4x for the fourth quarter, as we connect additional wells and raise and deploy higher levels of partnership capital.

With regard to Atlas Energy LP, we generated distributable cash flow of $23 million and distributed $0.46 per unit for the period, representing approximate one times coverage ratio. This distribution represents 70% increase from the $0.27 per unit distributed for the prior year third quarter and a 4% increase in the second quarter of 2013.

Going forward, we expect ATLS to continue to maintain minimum coverage on its cash distribution as ARP and APL both expect to maintain ample coverage ratios in future periods.

Atlas Energy DCF included $9.5 million of total cash distributions from APL, representing an almost 70% increase from the prior year third quarter. These distributions included almost $5 million of incentive distribution rates, approximately double the amount from the prior year third quarter, as ATLS continue to share significantly in APL's growth.

Atlas Energy DCF for the period also included over $16 million of cash distributions from ARP, a 75% increase in the prior year third quarter and an almost 25% increase from the second quarter of 2013. ARP distributions for the quarter included approximately $1.7 million from incentive distribution rates, a 40% increase from the second quarter of 2013.

Cash G&A expense for Atlas Energy on a standalone basis was $1.7 million for the period, a slight decrease from the second quarter of 2013 due to moderation of seasonal expenses incurred in the prior quarter including Annual Shareholder Meeting and a compliance costs.

Finally, I would like to quickly mention, ATLS' strong standalone balance sheet at September 30, which had $18 million of cash in an undrawn $50 million of credit facility, along with leverage below three times.

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

Edward Cohen

And I'm going to call on Sharon for questions now.

Question-and-Answer Session


And your first question is from Stephen Maresca of Morgan Stanley.

Stephen Maresca - Morgan Stanley

I have one question, one for Matt, one for Ed and one for Sean. Matt, I just wanted to talk a little bit about the Marcellus. You connected eight wells in Lycoming, you said it had strong initial flow rates, but the limitations of infrastructure you spoke about, and you also said how basis is improving. If you can give a little more color on how soon that infrastructure is getting resolved. Do you see the improving basis continuing over the next few months and how could this change your drilling activity in the region?

Matthew Jones

I think that the improvement in the completion of certain infrastructure projects in the region is part of what's led to the improved pricing and the reduction in the bases differential. My believe is that the delta between Henry Hub pricing and Leidy pricing will continue to contract.

We're seeing that as we speak, as recently as this morning we saw the differential decline to $0.40. We had mentioned, and I know you are an observer of the market, I mentioned in prepared remarks that going back to the second quarter of this year, the Leidy pricing differential was $0.13. You could argue that that was a period of time where the supply demand balance was more balanced and therefore more reflective, of what pricing should be in the Leidy market.

Nonetheless, I think our expectation is that pricing will continue to improve, certainly through the winter months. That we'll continue to see volatility in pricing going forward, I would hope and expect that we won't see, nonetheless even with volatility, the pricing extremes, the negative pricing differentials that we and the industry experienced in the third quarter of this year.

You had also asked about potential drilling locations. In our view of that, we do have a fairer number of additional sites that are in reasonable close growth proximity, in some cases offsetting the wells that we drilled that are so productive in Lycoming. We are monitoring of course, the pricing circumstance that's evolving in Leidy that to some degree has an impact on our thought process in moving forward in drilling wells that are offsetting, close to the wells that we've drilled in Lycoming.

We are encouraged obviously about what we've seen with pricing. We're extremely optimistic and encouraged by the production results that we achieved in Lycoming, the intersection of all of that may very well lead us to exploit some more opportunities next year on our Lycoming acreage.

Stephen Maresca - Morgan Stanley

Just moving to Ed. Ed, you alluded to the potential of the new funding vehicle within, are connected to Atlas and Atlas Growth Partners. I was just wondering if you could give any further thoughts as to the timing of the vehicle or more precisely how it is going to work to help Atlas?

Edward Cohen

I'm afraid, Steve, I have to limit myself to remarks we've already made, but give you an update on our feelings about it. As most people know from prior public remarks, Atlas growth is intended to be, just what it says it is, a vehicle for growth not for maintenance, but for making it possible for ATLS to have a unit, which is really visibly developing an E&P business without orientation toward maximizing cash distributions. We've said that before and nothing is changed there.

In the meantime, our key executives, including myself are working assiduously to make sure that Atlas growth is a success. It's being done through a private placement, which is why we're inhibited as to what we can say, but we are quite satisfied with the progress we're making and whereas a year or two to go public with information, as any of you are to hear about it, but that's not within our control. That's all subject to legal considerations.

Stephen Maresca - Morgan Stanley

And then, Sean, I do want to just discuss two of the add-backs to distributable cash flow. First, that $4.76 million well construction completion margin earned in the DCF reconciliation. So just to understand, that's money you definitely are going to receive, that's happened, but you're not getting it until the fourth quarter, so you're accruing it in the third quarter or am I reading that wrong?

Sean McGrath

We deployed capital. So we have a number of wells scheduled for the partnership programs like we normally do and that team did a great job of deploying that capital. Four of those wells are scheduled to be included in the partnership programs during the third quarter.

Under the partnership agreement, we did all the activities to earn that revenue that we would normally get, but just due to the timing of the cash flows from the partnership funds, we couldn't recognize it under GAAP. But there may have been a case, but we didn't want to be overly aggressive. And so we didn't recognize it for GAAP purposes, but we did put it into distributable cash flow, because we did earn it, do everything that we needed to earn under the partnership agreements. So that's why that adjustment is there.

Stephen Maresca - Morgan Stanley

And then the second one, that $13.3 million of add-back on the premiums paid on swaption derivative contracts. Could you just explain a little bit like that is adding back, why it is so big as well?

Sean McGrath

Those swaption premiums relate to the EP Energy acquisition. What we look to do with the swaptions in terms of hedging the production from acquisitions is that upon announcing the acquisition, we want to take as much commodity, price exposure off the table as soon as possible, because we've already signed the agreement. So we're not allowed to hedge those volumes for the acquisition until we actually acquire them under our credit agreement. So the one way we can hedge them is by utilizing swaptions.

And what that means is that we pay a premium to enter into a swap and that premium allows us the almost a walk away right from those swaps, if in case the acquisition isn't consummated. So we do that to take as much risk exposure off the table as possible. Technically, you might if our credit agreement did allow, you could enter into a swap. But if the acquisition did not close, then we will have to walk away it and pay a break fee, which depending on where commodity prices move that break fee could be significant.

So the premiums on swaption is really kind of a prepaid break fee, just for a short period of time. These swaptions only last for a period of, let's say, two, three months, so it gives us enough time from announcement, and so the expected close date for us to determine whether or not we're going to do the swaption, entering into swap.


And the next question comes from Praneeth Satish of Wells Fargo.

Praneeth Satish - Wells Fargo

Just a couple of quick questions for me. So both APL and ARP reduced their 2014 distribution guidance expectations, but it looks like there's no mention of any distribution guidance reduction at ATLS. I guess how should we interpret this? Are you still comfortable with that 250 to 280 range?

Matthew Jones

You have odd number of moving parts that are present, and of course it gets magnified when you go to the higher company, but we are satisfied with it because our expectations are that ATLS will in fact be able to comply with that guidance.

Praneeth Satish - Wells Fargo

And then, just breaking, getting a little more granular. So you gave 2014 distribution guidance at ARP. Can you just tell us what you're assuming for Leidy basis differentials there? Did you anticipate this kind of narrowing of differentials or are you assuming something a little bit more conservative?

Sean McGrath

For 2014, we assumed a range because we expect that during that winter months that will tighten, during the summer months it could widen. I'd say, we're using an average because with each period it's going to be different, let's say, an average overall for the year of somewhere in the range of $0.55 to $0.65 somewhere in that range on average. I don't have it front of me, but somewhere in that general category.

Praneeth Satish - Wells Fargo

And then, I think you mentioned in the prepared remarks that you expect ARP's leverage ratio to decline below 4x by the fourth quarter. Just wondering if there is any acquisition related adjustments in that number or is it just a straight GAAP calculation?

Sean McGrath

No, it's a straight calculation. Our leverage ratio and our credit agreement, it's annualized from using the second quarter, so for the third quarter that would be basically take the trailing three quarters and kind of do the math to get into our annualized rate. The fourth quarter also assumes the cash coming in from fund raising for the partnership programs, so the leverage ratio will be impacted by that with the cash coming in.

Praneeth Satish - Wells Fargo

And just last question for me. So it looks like the partnership had a pretty successful year with respect to acquisitions in '13. I guess heading into 2014, do you have any expectations with respect to acquisition spending? Do you think spending in '14 could match or exceed 2013 levels?

Edward Cohen

This is not an accounting answer this is a response to market conditions and our past experience. We don't see any reason, why acquisitions should not be a strong in the futures, they had been in the past. What we have seen is that the industry as a whole has been readjusting its expectations and the market has been responding to the industry into certain way, but this has been across the boards.

And so we feel the uniqueness of our vision as to what we want, which often leads us in areas, where we're very eager to make acquisitions that others for their own reasons are eager to dispose off, gives us tremendous opportunities and the variety of approaches that we've been able to utilized, suggest that we should be able to get out fair share of those opportunities. The opportunities are definitely there.


The next question is from John Ragozzino, of RBC Capital Markets.

John Ragozzino - RBC Capital Markets

Considering the nature of you guys have success on the horizontal development front areas, such as the Marble Falls and the Mississippi and, Marcellus, et cetera. Can you give us a feel for where you see the total portfolio decline curve heading, just considering the impact along the high rate development you're seeing?

Matthew Jones

I'll let Sean answer the decline rate question, but just a point of clarification. The drilling that we're doing in the Marble Falls is all vertical currently. That doesn't get to heart of your question, but I just want to make sure it's clear that that drilling is vertically oriented, all of it right now. The drilling we're doing in the Mississippi Lime and elsewhere is horizontal.

Sean McGrath

The overall decline we're forecasting to be in '14 about that is between 11% and 13%. So that takes into account the new drilling that we're doing. Obviously, benefiting from the low decline, EP Energy drive gas assets, but the overall portfolio we're looking about 11% to 13%.

John Ragozzino - RBC Capital Markets

That brings me over to the Marble Falls area in specifics. When considering the impacts of the additional formations that you guys have discovered, is this a project that you consider using a commingled approach to or is this something that's going to require, I guess coming back and re-completing different zones base on the pressure differentials?

Matthew Jones

I'm going to allow Mark Schumacher to answer that question. Mark, I hope he is still on the call, but Mark would you like to address that question?

Mark Schumacher

The development of our Marble Falls program in the vertical well bores we are commingling the formations being Barnett, Marble Falls and some of the shallower zones, Caddo. In areas that we have very prolific shallow opportunities, we may look at drilling incremental wells to fully develop, but right now we're able to commingle, and upon initial completion the pressures are all such that it makes the most sense to commingle that and Railroad Commission allows that.

John Ragozzino - RBC Capital Markets

Do you have a total D&C for call it all three?

Matthew Jones

I am sorry I couldn't hear the question?

John Ragozzino - RBC Capital Markets

The total development costs for wells considering all the formations that are targeted?

Matthew Jones

The development costs for all of the formation?

John Ragozzino - RBC Capital Markets

Yes, if one well were to target all three in a commingled basis?

Sean McGrath

We're probably looking between the $900,000 and $970,000, probably about a five stage completion, be in three different intervals of Barnett, of Marble Falls and the Caddo completion.

John Ragozzino - RBC Capital Markets

And then just, I guess a big picture, can you maybe perhaps give us an idea what are the largest or most significant operational hurdles you see across the portfolio and perhaps rank order them by the tax production?

Matthew Jones

Mark, I'll take a shot at that and then maybe you can add to the summary, but my view of operations challenges in the company, are really great opportunities frankly. And we had mentioned that in the Mississippi Lime and Marble Falls, water disposition and water handling is our primary expense, the highest of all of our expenses.

The good news is we're able to address that directly, specifically, and we're able to attack that, and we're adding to our infrastructure that will have the benefit we believe of substantially reducing our water handling costs, especially in the Marble Falls going forward.

So we're hitting some of the key areas where we have the opportunity to reduce operating expenses, some might refer to them as challenges. I think that it really does present an opportunity for us to continue to lower our LOE costs really across the board. I would say that Mark Schumacher and team in particular are doing a great job across our business all the basins we're operating.

The people that we have in place, many of who have joined us from past acquisitions and have become great Atlas employees are doing really a fine job of maintaining costs across the board. But Mark, I'll let you, got to add to that or correct anything I've said.

Mark Schumacher

Electricity is also kind of a primary cost driver for us in areas such as Oklahoma and we're refurbishing some of our electrical grid though the local co-ops and such as that. The EP Energy, former E&P Energy assets that we've acquired, the coal bed methane. Teams are doing a great job of maintaining the costs controls in place and we're with very flat production. So we've been very pleased with the integration of these assets.


The next question is from Michael Peterson of MLV & Co.

Michael Peterson - MLV & Co.

Couple of questions remaining for me. I think most of them will be for Sean. First one would be the $19.4 million acquisition and related costs. Can you give us a little more color as to what the breakdown for those costs would be?

Sean McGrath

What we include within there are generally, for a completed acquisition it would be the finder's fee, the legal costs, other different types of things such as reserve engineering costs that we incurred in evaluating the acquisition. There is a small amount of allocated labor, outside labor, for helping us to do the work and consulting costs.

There is also cost in there for acquisitions that we reviewed that we have not consummated, so we track those costs for pursuing other acquisition, which were acquired to expense. So there is a general typical cost. And as a percent, those costs are higher at this period, in terms of gross, but as percent in terms of the purchase price. They generally hover around 1% or 2%, so it's been fairly consistent if you look back over the last two years or so.

Michael Peterson - MLV & Co.

That makes sense, so I expected there would probably be more related costs given the size of the deal and I appreciate the confirmation on that. A follow-up to Steve's question on the construction and completion margin earned adjustment that you made. Will at any time those revenues qualify for GAAP? Is that something that we will see in the fourth quarter and you'd have to adjust back out or will those be excluded on a go-forward basis?

Sean McGrath

That's why we try to provide the clarity with it, we didn't want to just bury it on the line. We try to make it very clear. Those amounts will be reversed out in the fourth, just for that purpose, so yes, it really has no impact in terms of overall for the two quarter period, this quarter and next quarter, it just has that timing aspect to it.

Michael Peterson - MLV & Co.

Is there any inference on that same point in terms of partnership funds coming in that that there are fewer funds, then maybe you have operational ability to deploy and you're hoping to catch up? Or is that not a correct assumption?.

Matthew Jones

No, I think that's not a correct assumption. It's just a matter that the calendar that we use came to an end on September 30, that we've been using a Mesopotamian calendar, or some other method of calculation, it would have been different. No inference should be taken as to funding, we're quite pleased with how funding is going.

Michael Peterson - MLV & Co.

Good, and probably even more confusing for me if you did select the Mesopotamian calendar. Last question for you, Sean, for the optionality portion of the swaptions, what was the expiration date for that piece?

Sean McGrath

I believe they were September 30, Mike. So I have to back and look it, it might have been August 31. I have to go back and take a look. The acquisitions closed on July 31. So we wanted to give it a little room in terms, because we signed the acquisition on June 6, June 10. So we wanted to give a subtle little room, because it's generally going to take 45 days to two months to close an acquisition, because of the title review. So when we enter into these, we try to give it enough time to allow us to make sure we're going to close on the deal.

Michael Peterson - MLV & Co.

So the option either expired or was exercised, and has been fully realized at this point?

Matthew Jones

That's correct. We exercised the swaptions, put them on, soon after we acquired the enterprise.


Meanwhile we have question from the line of Abhi Sinha of Wunderlich Securities.

Abhi Sinha - Wunderlich Securities

I have a question. Basically I just want to evaluate or understand the strategy that you guys have behind adjusting the revenues that you get from effective date of an acquisition versus closing date? Was adjusting that into purchase price, does this meant cleaning and keeping the EBITDA level more cleaner that way, so Street can get a better perception and more clarity on that? So any word on that would be helpful.

Matthew Jones

The rationale behind it is that the way we finance the acquisitions, we issue equity, so we announce the deal on June 6. That was, I can't remember the exact date. We did an equity offering right after the announcement. We do that to take the exposure in terms of movements in our unit price. We try to issue the equity as soon as possible after announcement to take that risk off the table. So those units get a full quarter distribution. They receive that for the second quarter as well as the third, whereas we didn't get to close the acquisition until July 31.

So really what we're doing is kind of essentially showing on a pro forma basis. We did get the cash for these acquisitions going back to that date, and that's why we present it. This is a one quarter anomaly. This quarter, obviously it would be two, because it ran through July, but it's a one quarter anomaly.

We look at it with that on a go-forward basis, even if you took those cash flows from the acquisition and it was below one times for that period. That's not a reflection on what our go-forward coverage ratio would be on our cash flow. So we strive to be in one times the area, it's not better. And I think in that period, it's just not an active reflection taking the full distribution out, without including the cash flows that we earned and received for that acquisition, for those periods.

Edward Cohen

We were simply is striving for consistency and that [technical difficulty] we were paying dividend or shares for an entire quarter, when the shares were actually only outstanding for a portion of the period. At the same time to deal with that we negotiate carefully to make sure we get the income from the acquisition at an earlier date. So the two really match and we think this is the fairest way of presentation.

Abhi Sinha - Wunderlich Securities

So just on the follow-up. So if I say, if this adjustment ends this quarter and in the next fourth quarter we will not see this adjustment and your well construction and completion margin would also be basically back calculated for GAAP purposes. What do you think your coverage ratio would look like for fourth quarter on a go-forward basis, assuming we don't have any acquisition in the fourth quarter?

Matthew Jones

We're still evaluating the quarter, obviously right in the middle of the fourth quarter at this point from a calendar basis. So like I said, our expectation is to strive to be at the one times coverage ratio basis. So we'll see how the quarter goes, obviously it depends on what we distribute in terms of cash, what our board determines the cash distribution will be. But our goal is kind of to be in that coverage ratio, both on a quarter as well as on a rolling four quarter basis.


Thank you. There are no further questions. I'd now like to turn the call over to Ed Cohen, CEO for closing remarks.

Edward Cohen

Thank you all for joining us. And we hope that the next quarter also will be one, where we can be quite proud of our accomplishments. We expect that will be the case. And we thank you for participating.


Thank you. Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect.

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