Aug 7, 2015
Executives
Brian Begley - VP, Investor Relations Edward E. Cohen - CEO, Atlas Energy Group Daniel Herz - CEO, Atlas Resource Partners & President, Atlas Energy Group Mark Schumacher - President Sean McGrath - CFO
Analysts
John Ragozzino - RBC Capital Markets Lee Cooperman - Omega Advisors Matt Schmid - Stephens, Inc. Gabriel Daoud - JPMorgan Brian Brungardt - Stifel, Nicolaus & Co.
Noel Parks - Ladenburg Thalmann Sean Sneeden - Oppenheimer Craig Shere - Tuohy Brothers
Operator
Good day ladies and gentlemen and welcome to the Atlas Energy and Atlas Resource Partners' Second Quarter 2015 Conference Call. At this time all participants are in a listen-only mode.
Later we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions] As a reminder, this call is being recorded.
I would like to introduce your host for today's conference, the Vice President of Investor Relations, Brian Begley. Please go ahead, sir.
Brian Begley
Good morning, everyone and thank you for joining us for today's call to discuss our second quarter 2015 results. As we begin I'd like to remind everyone that during this call we will make certain forward looking statements and in this context forward-looking statements often address our expected future business and financial performance and financial conditions and also contains words such as expects, anticipates and similar words or phrases.
Forward looking statements by their nature address matters that are uncertain and are subject to certain risks and uncertainties which can cause actual results to differ materially from those projected in the forward-looking statements. We discuss these risks in our quarterly report on form 10-Q and our annual report also on form 10-K particularly in item 1.
I would also like to caution you not to place undue reliance on these forward-looking statements which reflects Management's analysis only as of the date hereof. The company undertakes no obligations to publicly update our forward looking statements or to publicly release the results of any revision to forward-looking statements that may be made to reflect events or circumstances after the date hereof or reflect the occurrence of unanticipated events.
In both our Atlas Energy and Atlas Resource earnings releases as always we provide a GAAP reconciliation to the non-GAAP measures we refer to in our public disclosures such as adjusted EBITDA and distributable cash flow. And with that, I'll turn the call over to Atlas Energy's Chief Executive Officer, Ed Cohen for his remarks.
Ed?
Edward E. Cohen
Thanks, Brian and hello everyone. We will have Daniel Daniel Herz, CEO of ARP, Mark Schumacher, President of ARP and Sean McGrath, CFO of both companies speaking after I speak.
I want to be very clear and direct. The present energy crisis has spawned a great deal of inaccuracy and misinformation.
Atlas Resource Partners, ARP and its general partner, Atlas Energy Group have certainly not been overlooked. Therefore, I really welcome this opportunity briefly to clear up some misconceptions.
To begin however, let me make it clear that continuation, let alone an intensification of current conditions will certainly challenge the Atlas companies. Together with our entire sector we face enormous adversity.
Investors should not underestimate the difficulties that we confront. Atlas Management however, does have a long record of exploiting adverse conditions to provide high returns to those investors who had confidence in us, but success of course is no guarantee of future benefit.
Fortunately however, our renewed caution and conservatism, although often despised during buoyant times has positioned us well to deal with the present situation. First, our capital needs are relatively small.
We are overleveraged, but not by much. Our revenues now and for the next four years are relatively well protected by hedges that already have a value well in excess of $300 million.
Simply put, regenerating a great deal more revenue and if we were dependent on sales of oil and gas at today's depressed spot prices and that provides us with a relatively favorable ratio of debt to EBITDA, that ratio should improve. First, because we are highly hedged through some years into the future and the strip pricing which increases for future years in industry parlance the strip is becomes state of contangos [ph] increasing strip pricing enables us on a continuing basis to layer in additional hedges, yet further into the future at prices considerably higher than the present depressed spot market and we continue to do that.
Secondly, we are taking steps to further reduce debt outstanding. We are well along in our efforts to obtain additional funding with which we will further reduce debt.
We will structure any additional funding so that this additional capital enhances prominent unit holder value. Now the second misconception, that misconception is that ARP like other E&P MLPs operates on a negative cash flow basis.
In fact, ARP for the second quarter had a static positive operating cash flow in excess of $0.50 annualized and the EBITDA should rise sharply by the fourth quarter. We are taking various steps to increase this amount even further including further reductions in cost.
And unlike many companies that have had their bank lines cut due to depressed pricing, ARP has just had its bank line reaffirmed at $750 million of which approximately $200 million is unused. Although our line was not increased, we did experience even under present adverse bank guidelines a substantial increase in reserves beyond our prior valuation and so we have a substantial cushion against possible further industry-wide reductions in the amount that banks are willing to advance.
Furthermore, we believe that the era of positive growth is not over. We plan to do more than simply pray for higher prices.
ARP CEO, Daniel Herz will shortly speak further on dynamic initiatives available to us. Finally, let me briefly say a few words about Atlas Energy Group.
AEG of course is more than just ARP of which it owns some 25 million units and all the incentive distribution rights. AEG also owns a substantial interest in Lightfoot, the general partner publicly held Arc Logistics Partners.
It is also the general partner of Atlas Growth Partners, the complementary energy company which recently completed its initial private placement with funding of some $230 million. AEG itself has been outstanding of less than $85 million.
It has substantial cash on hand and is furthermore in advanced discussions to refinance this debt on a long-term basis. And now, Daniel, continue.
Daniel Herz
Thanks Ed and good morning everyone. It has been quieter three months since we last spoke.
Needless to say our stock price at both, AEG as well as ARP have not been immune to this catastrophe. I'm pleased to report however that our actual business unlike our stock prices has been generally insulated and well protected from the volatility that has gripped the energy sector.
Atlas Resource Partners has approximately 85% of our projected margin hedged or fee based through 2018. We have also been successfully at blocking and tackling of cost reductions and savings.
Our general and administrative expense is down $9.5 million on an annualized basis or 18% from the fourth quarter of 2014. Our production expense is down $25 million on an annualized basis or 12% from the fourth quarter of 2014 and our CapEx for 2015 is now expected to be approximately $140 million versus our guidance of approximately $175 million.
This is total annualized cash flow savings of approximately $70 million. These two factors ensure a stable cash flow stream for the coming periods.
So much for the past and the future. At the present time, we are focused on three areas, which we believe will drive value for our stakeholders over the short, medium and long-term.
First, we are focused on reducing leverage to a more appropriate level. As Ed said, we are slightly over-levered for this environment.
Our target leverage is 3.5 times debt to EBITDA and we hope to drive that even lower over time. Second, we are focused on providing long-term comfort around our distribution.
Atlas Resources should be able to self fund all capital investments while being able to provide a stable and substantial distribution. Finally, we are formally working to find a partner that will allow us to take advantage of this low commodity price environment and acquire assets which over time can be dropped down into ARP.
This should provide medium and long-term visibility of distribution growth which I believe will ultimately allow us to trade at a premium valuation. Appropriate leverage, distribution comfort and long-term distribution growth, these are the objectives we are focused on and I believe over the coming months we will be able to fully express to the market these initiatives.
These are not new concepts for this executive group which has operated successfully through commodity cycles similar to the current environment. With our previous four public energy companies, with this same or similar strategy, we achieved total returns to our unit holders and shareholders of 549%, 930%, 1535% and 5259% from the trough [ph] of the market.
I understand during challenging periods like we are experiencing today, it is difficult to conceive of these types of returns from this point forward. Nonetheless, we have the appropriate group and focus to execute and achieve these types of results.
Time will tell. Second, we at Atlas have a world-class operating group led by Mark Schumacher and Dave Leopold and supported by 600 of the best energy professionals in North America.
Finally, our assets at Atlas Resource Partners anchored by 11,600 operated wells across 12 states, coupled with our stellar hedge book and investment partnership business provides us with a stable cash flow stream. Now with respect to the second quarter, we experienced a period in line with our expectations.
As Sean referred to on our first quarter earnings call, the second quarter is a low point each year in our recognition of margins associated with our partnership business. As such we saw distribution coverage drop to 0.83 times for the quarter.
We expect the third quarter to be consistent with the second quarter with a significant increase in EBITDA in the fourth quarter. Furthermore, given that were are 81% natural gas and are directing fresh efforts towards oil rather than natural gas we expect gas equivalent volumes to continue to decline, but EBITDA to rise meaningfully in the fourth quarter as I mentioned.
As Mark will discuss, ARP will be drilling and turning new wells into line in the third and fourth quarter, both for our own account as well as for the partnership business. All wells are being drilled on our Eagle Ford Shale acreage in South Texas.
As such we expect oil volumes to be roughly flat to slightly down this quarter and begin increasing in the fourth quarter and into 2016. I will now hand the call over to Mark to discuss the operational achievements in greater detail.
Mark?
Mark Schumacher
Thank you, Daniel. We continue to focus on the fundamentals as states on the first quarter earnings call which include production volumes, production costs and capital efficiency.
During the second quarter we have made the following progress. We add the Arkoma assets to our production profile.
This asset has a 5% annual decline. Our teams continued making progress and reduced production costs by 5% compared to the first quarter of 2015 and 12% compared to the fourth quarter 2014.
Drilling and completion costs are down by over 30% compared to wells completed during the fourth quarter of 2014. Let me walk you through some additional detail associated with our progress during the quarter.
During the second quarter we produce 271 million MCF equivalent per day which is comprised of 81% gas, 12% oil and 7% liquids. Over the last few years we have focused on building a company with a stable production base, a diversified geographic portfolio and product mix.
This includes adding the Arkoma asset which was effective as of January 1, 2015. As a reminder, the majority of our production comes from our low declined assets in Appalachia, Barnett in coalbed methane areas.
These are the three areas that make up 91% of our second quarter gas volumes and have an annual decline rate of 9%. As Ed and Daniel mentioned, a significant portion of our gas production is hedged at prices exceeding $4 per million cubic feet through 2018.
Our production base also includes our low declined non-operated position in the Rangeley field, a CO2 enhanced oil recovery project operated by Chevron. This production makes up approximately 45% of our total oil production and has an annual decline of approximately 4%.
During the second quarter we have reduced production cost by 5% compared to the first quarter and 12% compared to the fourth quarter 2014. Excluding our Eagle Ford and Rangeley assets, which were not in the prior year reporting period and comparing like properties against the second quarter 2014 we have reduced our production cost by 21% or $35 million on an annualized basis.
Our teams remain focused on identifying operational efficiencies and contract renegotiation to enhance production margin. For example, we are seeing significant savings in our water disposal costs which are down 21% compared to the first quarter 2015 and 25% compared to the fourth quarter 2014.
The reductions are due to adding water disposal capacity and installing water disposal pipelines from producing wells to the disposal wells, plus eliminating the need to truck water and results in significant cost savings. Another production expense where we will see significant savings over the coming periods is compression.
Our teams have been evaluating our compression needs which have resulted in consolidation of the amount of compression needed. Hence we have released certain units and increased operating efficiency.
The reduction in compression has not been fully realized in cost savings to date. We expect to see savings during future periods as these rental compressor contracts term expires.
We also continue to evaluate and optimize our artificial lift needs such as downsizing pumping units and converting units to [indiscernible] lift and gas lift. This has resulted in a 24% savings compared to the first quarter 2015 and 41% savings compared to the second quarter 2014.
As part of our adjusted 2015 development plan, we currently have two drilling rigs developing our Eagle Ford asset. We will drill three Eagle Ford wells for our own account and then transition to our 2015 investment partnership program.
We expect to see drilling and completion cost savings of over 30% compared to what we experienced at the end of 2014. The three wells we are drilling for our own account have an average laterally length of approximately 8000 feet and are expected to generate returns in excess of 20%.
An example of the cost savings that were realized as we finished our 2014 development plan is completion costs per stage declined 44% from the fourth quarter 2014 to the second quarter 2015. This was achieved through both vendor cost reduction and operational efficiencies.
The lower cost also included an enhanced fracture stimulation designed to achieve greater conductivity which is expected to increase well performance. These second quarter results were achieved not only in a challenging product price environment, but also in extreme weather conditions affecting Texas and Oklahoma where we had the equivalent of a 100-year flood.
Power outages and flooding impacted some of our production in these areas. Also third-party planned outages in our Eagle Ford area and third-party pipeline maintenance projects in our Appalachian area also affected our production in the quarter.
Each of these impacts are behind us now, so we estimate a production impact of 2% to 3% for the quarter Thank you to all of our dedicated employees focused on enhancing production, reducing costs and operating efficiently and safely. Thank you for being a part of our call this morning.
I will now turn it over to our CFO, Sean McGrath.
Sean McGrath
Thank you, Mark and good morning to everyone. Regarding our second quarter financial results for ARP we generated adjusted EBITDA of $64.7 million and distributable cash flow of $25.4 million or $0.27 per unit.
We distributed approximately $0.325 for the period which translates into a coverage ratio of 0.83 times for the second quarter and one times for the first half of 2015. As Daniel noted earlier, I did mention on our first quarter call that the second quarter is traditionally the trough period for recognition of our investment partnership margins during the year.
And as such we expect the cash distribution coverage to be below one times for this period in our original guidance. Based upon an assumed partnership program fund raise of at least $150 million during 2015 we believe we will recognize approximately $27 million of investment partnership margins during the second half of 2015 or an average of $13.5 million per quarter which is approximately $7 million more than the $6.7 million of partnership margin recognized during the second quarter.
Pro forma for normalized partnership margin our second quarter coverage would have been approximately one times. Production margin for the second quarter was approximately $69 million which represented 6% increase when compared with the prior year's second quarter and a 6% decrease from the sequential quarter.
The approximately 4 million increase from the prior year second quarter was principally due to margin contributed by the Eagle Ford and Rangeley assets acquired since the prior year. The $5 million decrease from the sequential quarter was due principally to lower production volumes resulting from highly challenging whether and deferral of originally scheduled drilling activity as well as lower unhedged prices partially offset by lower production costs all of which Mark mentioned earlier.
With regard to commodity prices, realized natural gas prices including hedges were $3.33 per MCF in the second quarter, $0.25 lower than the first quarter of 2015 as Henry Hub first of month prices were $0.35 or 12% lower when compared with the first quarter. Overall approximately $73% of our natural gas production was hedged at $3.76 per MCF for the second quarter of 2015 compared with 79% hedged at $3.86 per MCF for the sequential quarter.
Regarding liquids ARP realized oil prices were up 3% or approximately $2.40 per barrel to slightly over $83 per barrel for the second quarter and WTI NYMEX prices rose approximately 20% to $58 per barrel in the second quarter. Once again we benefited from our significant hedge position as approximately 100% of our crude oil production volume was hedged for the second quarter at $83 per barrel compared with 90% hedge for the sequential quarter.
Regarding general and administrative expense, net cash G&A was $10.7 million for the period or almost $1 million lower than the first quarter of 2015 due to lower compensation and other costs. Due to cost reduction issues we executed during the first half of 2015 we expect full year 2015 cash G&A expense to decrease approximately 20% compared with the full year 2014.
Total capital expenditures were approximately $27 million for the second quarter including approximately $13 million associated with maintenance capital compared with approximately $43 million of total CapEx for the sequential quarter, due to the lower investment partnership contributions and direct well drilling. The second quarter amount included approximately $21 million for direct well drilling and investments in our programs and the remainder associated with leased acreage, gathering and disposal costs and other items.
Regarding risk management activities, while we like everyone else on this call will rather have much higher commodity prices, ARP continues to benefit from its prudent hedging program that has been methodically but opportunistically developed over the last few years. Our hedge book got a fair value of approximately $330 million as of yesterday.
Our position is covering approximately 190 billion cubic feet of natural gas production at an average contact floor price of approximately $4.20 per MCF for the period through 2019 and approximately 6 million barrels of oil at an average contract floor price of over $80 per barrel for the period through 2019. Our fair price for oil and natural gas continue to be pressured.
Forward curves for both commodities continue to be state of contangos [ph] as Ed mentioned. But natural gas forward prices averaging approximately $3.25 per MCF for 2016 through 2019 or approximately $0.45 above the September contract and crude oil forward prices averaging approximately $56 per barrel or $12 above spot prices.
Please see the tables within our press release for more information about our hedges. Moving on to ARPs liquidity position and leverage.
At the end of June we had approximately $200 million f total liquidity under our recently reaffirmed $750 million credit facility borrowing base with a leverage ratio of 4.5 times compared with the max leverage ratio covenant of 5.25. With regard to Atlas Energy Group, we generated distributable cash flow of approximately $5 million or $0.19 per unit for the period compared with $5.4 million for the first quarter of 2015.
The slight decrease between periods was due to a full quarter's interest expense on ATLS of the term loan partially offset by $1.4 decrease in cash G&A expense due to cost reductions and seasonality of expense. At June 30, ATLS had a debt balance on its term loan of $74.5 million net of an $8.2 million unamortized discount with a cash position of approximately $12 million.
This represents a debt reduction of approximate $33 million between periods which is principally due to the net proceeds from the sale of the Arkoma assets to ARP during the quarter. We expect to continue to meaningfully reduce the debt at ATLS through the remainder of 2015 with cash flow generated from ownership ventures.
With that, I thank you for your time and I'll return the call to our CEO of Atlas Energy Group, Ed Cohen.
Edward E. Cohen
Thanks very much, Sean. Malorie we are ready for questions.
Operator
Okay, thank you. [Operator Instructions] Our first question comes from the line of John Ragozzino from RBC Capital Markets.
Your line is now open, please go ahead.
John Ragozzino
Good morning, gentlemen.
Edward E. Cohen
Hi, good morning, John.
John Ragozzino
First I just want to check-in on, you had the February refines in the second lane and then the subsequent reaffirmation of the borrowing base at $750 last month, just to clarify are you going to be subject to a further redetermination in October and if not when can we expect to see the next review?
Sean McGrath
Sure yes. The next redetermination is November 1st.
You know, as Ed mentioned, I think with regard to our borrowing base we actually reaffirmed at a higher level than the 750, so right now we believe we have adequate cushion. Obviously it's going to be dependent upon the price decks for the banks, but we believe that we are in good position and we shouldn't have any issues with regards to the borrowing base since the fall redetermination.
John Ragozzino
Great, thanks Sean, and then Ed made some comments about the recent activity of layering on additional volumes, if can you give me a feel for what type of price levels that you guys are really comparable with when you look to '17, '18 and beyond than somebody lesser hedged the years and if taking it one step further, perhaps give me an idea of we were to consider the strip were to be actually come to fruition in '17 and beyond what kind of sustainable long-term distribution would you be able to support absent any meaningful state of contangos that we hold at 18 at 350 and beyond into perpetuity?
Edward E. Cohen
I think it is very difficult to make projections into perpetuity. We find it hard enough to do for 2015 and 2016, but Sean, why don't you answer the first part of the question as to our hedging policies?
Sean McGrath
So John, yes. I mean, we try to be methodically opportunistic.
I think when you look at the prices right now and the curve when you compare it to where the spot is as well as the fact that the bank, the price decks that the banks use for their redetermination is generally much lower than the strip. So hedging at these levels is not only locking your margin, but it's accretive to what the banks would price it in terms of determining the borrowing base.
So we try not to take a significant position in any one period. We try to be methodical and put a little bit on each period.
So I think when we look at our crude oil hedge volumes I think they are good opportunities to layer some additional layers on there, knowing that we'd see spot prices where they are at right now. You could hedge at least $12 below that spot price level.
So I think we'll continue to monitor it and I think we'll be opportunistic in the market.
Daniel Herz
And John, it's Daniel. Just do to give you my perspective around the long-term with regards to our EBITDA and forecasted cash flow using the strip.
Keep in mind when we display our hedge percentages it's based on the quarters, the current quarter's or the past quarter's actual production level. So when we look at natural gas and the decline in natural gas that we are allowing we’re actually substantially more hedged as we look at future production and then we're gaining some really substantial margin from the expected oil production that we're bringing on giving the returns that we experienced in the Eagle Ford and very high returns that we experienced through developing through our partnership business.
So when I think about and when I analyze the numbers over the long-term using the strip I see I EBITDA and cash flow numbers consistent with current levels or even higher.
John Ragozzino
That's really helpful and I can certainly appreciate Ed's comment about the ability to look out that far, it's impossible to ask I certainly understand. I guess another quick one on Rangeley field if you assume $50 current type strip prices what are the cash listing cost and cash margins look like?
Edward E. Cohen
Mark?
Mark Schumacher
The LOE is running between $20 and $30 a barrel and at $50 of production margin this is still very attractive out there.
John Ragozzino
And I guess one last I guess bigger picture question. With the current cost of equity just rigorously blown out at north of 40%, but depending upon where we open up this morning, what kind of financing leverage do you have longer-term to execute some sort of strategic transaction?
Edward E. Cohen
I think we have a lot of leverage from that fact that we are not in a troubled position. The fact that we has is positive operating cash flow really gives us strength.
So we'll pick and choose our situations, but I think any transaction we do should result in bringing our followers to their feet with joy.
John Ragozzino
That's fair enough. I appreciate it.
Thanks for the color.
Edward E. Cohen
Thank you.
Daniel Herz
Thanks John.
Operator
The next question comes from the line of Lee Cooperman with Omega Advisors. Your line is now open.
Lee Cooperman
Yes, thank you. I realized to forecast the future is very difficult okay, but I guess I am trying to figure out if I said to you except the strip for oil and gas strip prices is accurate and within the confines of your bank agreement I have two questions with the opposite and the spectrum.
One, do you expect both Atlas and ARP to be paying a dividend next year one, and number two on a scale 1 to 10, 10 being high what is your confidence that you will be able to meet all your financial obligations to service your debt?
Edward E. Cohen
We're extremely confident that we can meet all of our obligations and service our debt. Again as to our distribution policies, they've always been set by our board which takes into consideration the totality of circumstance.
The important thing I think is what I said earlier is that, that we've got the capacity to pay dividends and distributions I should say and it's really up to board to make a determination taking everything into consideration.
Lee Cooperman
Does your bank agreements, your cash flow give you position to buy debt that is selling at a significant discount or you are really prohibited to doing so at the moment?
Edward E. Cohen
Sean?
Sean McGrath
We are not prohibited from buying back debt, certain pieces of debt. That being said, as you know we take into consideration of a lot of other factors including our liquidity, our cash distribution policy and so it is not only something that we consider, it's prudent to do that, but we take all those factors into account to make sure we are coming up with the best strategy in other words [ph].
Lee Cooperman
So in terms of my questions, would you respond to would you feel comfortable by your ability to service your debt, but you are silent on the dividend intensions going forward into 2016?
Edward E. Cohen
All right, with our company nothing has changed, but obviously in the outside world there's a lot of…
Lee Cooperman
Well, you can't stay that Ed, what's changed, your previous guidance was for $0.70 dividend in Atlas and the board deferred action until next year. So my question is, if you had to make a guess would the board reinstate a dividend in 2016 or it's uncertain at this point in time, that's all?
Edward E. Cohen
I never would have been in a position to know what a board is likely to do. I would point out that the Atlas situation and the ARP situation are very different situations.
ARP has a continuing strong cash flow and conducts an active business. ATLS has to take into consideration the fact that it's always been more of an incubator of new companies and in a period when cash is not readily available, as was indicated there's a very high cost for new cash the company which is in an incubator type situation has to take into consideration the advantage of cash being retained in a way that ARP does not.
Lee Cooperman
All right, thank you.
Edward E. Cohen
Thank you.
Operator
The next question comes from the line of Matt Schmid with Stephens. Your line is now open.
Matt Schmid
Hey, good morning.
Edward E. Cohen
Hi.
Matt Schmid
You know in the near-term focus at Atlas Energy Group meeting debt reduction and the distribution deferral, do you have any update just kind of operationally or strategically opportunities you're looking at there? I know last quarter you mentioned potential midstream opportunities?
Edward E. Cohen
All right. I think that the situation in the energy field is so volatile that it's very hard to say exactly what we'll do, but as you know, ATLS has a history of generating new opportunities and we're certainly alert to all possibilities.
We're working, but it is not an appropriate time to make any disclosures.
Matt Schmid
Okay, great, well that makes sense. Well, that's all I had.
Thank you very much.
Edward E. Cohen
Thank you, Matt.
Operator
The next question comes from the line of Gabe Daoud with JPMorgan. Your line is now open.
Gabriel Daoud
Hey, good morning guys.
Edward E. Cohen
Good morning, Gabe.
Gabriel Daoud
Just do you guys have any initial thoughts on 2016 capital program if we should expect something so much in 2015 in $772 million-ish call it?
Daniel Herz
Yes Gabe, it's Daniel. Just I want to point out that I did update our guidance on CapEx for 2015 to $140 million.
We are working on providing long-term guidance as we move towards the end of the year. I think for modeling purposes at this point a flat CapEx expectation in 2016 and may be even down given the significant cost savings we're seeing as Mark alluded to would be appropriate, but I expect that we'll provide long-term guidance including 2016 as we head towards the end to the year.
Gabriel Daoud
Got you, thanks gentlemen. It's helpful.
And then just may be touching on the joint partnership, any updates there in terms of fund raising, I mean if you, I guess if the guidance still stands about $150 million range this year and in 2015?
Edward E. Cohen
The guidance really is a budgetary figure, it doesn't represent our expectation necessarily. What we have found is the investment a private investment channel has a stronger contrarian aspect.
So in fact, our most successful years in terms of the amount of funds raised occurred in 2008 and 2009 when no money was available and as you remember the great panic was underway. So we weren't surprised to find that the 2014 program not only had an increase over the prior-year although conditions in energy were much worse, but the largest amount of fund raising occurred in December.
In fact between the private placement for Atlas Growth Partners and the investment programs we raised a couple $100 million just in the last six months or so. So things are very bullish strangely enough, exactly the time when energy conditions are the worst.
Gabriel Daoud
Great, thanks Ed. That's helpful.
That's all I had guys.
Edward E. Cohen
Thank you.
Daniel Herz
Thank you.
Operator
The next question comes from the line of Brian Brungardt with Stifel. Your line is now open.
Brian Brungardt
Good morning guys and thank you for taking my call.
Edward E. Cohen
Hi, Brian.
Brian Brungardt
And I appreciate the color earlier on the drilling plan and the expected EBITDA ramp back half of this year, I guess as it relates to the significant ramp planned around the joint partnership activity during the second half, what price deck is that using?
Daniel Herz
So Brian, it's Daniel. We always contemplate the strip price and then run sensitivities off the strip price.
So it would be strip as of earlier this week.
Brian Brungardt
Got you. Thank you, and then to dovetail on that I guess, do you continue to expect and to spend all of the capital in 2015 or should we expect for some of that deployed into 2016 if you know, strip continues to be under pressure?
Sean McGrath
Hey Brian, it's Sean. Yes, I think when you historically look at how we deploy capital, we generally say that the third and fourth quarters are probably the high marks in terms of the seasonality of the year.
The second quarter is kind of the low point. The first quarter kind of lies in between.
So when we raise that capital by December 31st, you know, there are amounts that roll into the first and second quarters in terms of the capital deployed. So I would expect that to continue, but obviously it depends upon timing of wells and rigs and Mark's team executing that.
So we feel pretty good about it.
Edward E. Cohen
And Brian, keep in mind we did defer substantial amount of CapEx from earlier in the year to the second half to allow ourselves to capture what we felt were going to be significant savings in the field. With that said, Mark and Dave in our groups are working to be most efficient in the development of our Eagle Ford Shale position and to do that we have multi-well pads there that will really require a certain sequencing, that isn’t dictated by the day-to-day spot prices.
Brian Brungardt
That is all I have. Thank you very much guys.
Edward E. Cohen
Welcome.
Operator
The next question comes from the line of Noel Parks with Ladenburg Thalmann. Your line is now open.
Edward E. Cohen
Hi Noel.
Noel Parks
Good morning. I just had a couple questions, when you were having discussions with potential partners, I think, I am especially thinking about financial partners, the folks you're talking with and meeting with, do they generally have or are they mainly driven by a particular few sort of the macro demand picture for gas, new chemical plants on the golf course as professional topic, are they more driven by thoughts about longer term supply and if that makes that bearish or you just meet with folks who have opinions all over the spectrum about longer-term gas markets?
Edward E. Cohen
I think it's fair to say that as in the general world the people that we talk to regardless of the conditions under which we're talking to them there are just an unending variety of approaches and opinions.
Noel Parks
Okay and I guess along that line, I am thinking that despite the overall negative tone in energy markets, but so much that's happening on the oil side, the volatility on the gas pricing side has really settled down. The gas is traded within a fairly tight trading range at least we can say for the last quarter.
So I was just wondering is that helping the bid-ask discussion as far as valuations for assets?
Edward E. Cohen
Is it helping which discussions?
Noel Parks
The bid-ask discussion?
Edward E. Cohen
Yes, I think that one of the things which is just a little disappointing to us is that we were at for long time negative by the fact that it was perceived that our holdings are primarily natural gas. We would have expected that with the relatively good performance of natural gas, the same people who were at negative because we were so highly involved with natural gas, although they were complementary about our shift into petroleum would have noted that we are different from most other companies that get compared to us.
So the stock market price also suggested that's been picked up, but it really should be. I think the information that was given about the very low declines that we expect to a large extent reflects the type of assets that we've purposely built and I also think in terms of the people who have sort us out to find whether we can work something out with them it has been a very strong commonality in that people recognize that the Atlas companies have a long record of handling crisis.
It seems extremely well as I said, the past is no necessary guarantee of the future, but that is a common theme that we do here that people recognize that Atlas has been through this kind of situation before, often goes into it with a great deal of preparation and comes out of it having a great deal of vagility. So Lord willing, we will be able to shine once again I hope.
Noel Parks
Thanks. That’s all I had.
Edward E. Cohen
Thank you.
Sean McGrath
Thanks Noel.
Operator
The next question comes from the line of Sean Sneeden with Oppenheimer. Your line is now open.
Please go ahead.
Sean Sneeden
Good morning. Thank you for fitting me in here.
Edward E. Cohen
Hey, Sean.
Sean Sneeden
Maybe thinking about the partnership program you guys have, any kind of initial indications of how the second half of the year is shaping up with sort of the conversations with folks, just given where commodity prices are today, I guess A, are you still seeing decent demand for that product and B, can you kind of give us a sense maybe even anecdotally of how returns or paybacks are looking in that product for the investors on a year-over-year basis or give us some kind of metric on that front?
Edward E. Cohen
Sean, I think we are lucky in that we have Freddie Kotek, who heads that division with us. Freddie, are you on?
Unidentified Company Representative
I am on Ed. Unfortunately thank you for turning it over.
You know, our tax year-end deal has hit the markets. All agreements are signed and we can't discuss it right now?
Sean Sneeden
Sure. Fair enough.
Maybe for Sean, I guess any kind of thoughts on mechanisms to boost liquidity here, for instance would you look at additional lien, just kind of create at least optically a little bit better liquidity as we go through or heading into 2016 or what are your thoughts around that?
Sean McGrath
You know Sean, I think we are heading on, I mean I think when we look at the situation we are considering everything. I think our liquidity situation we're considering everything.
I think our liquidity situation is good. That being said the two financial offside always want more liquidity.
We do have capacity to take out additional second lean I think with our borrowing base where it is at right now like I said I think we could have gotten another $60 million increase from the $750 million that's there which gives us a decent amount of cushion especially as we execute our drilling in the second half of the year putting more reserves and therefore possibly increasing the borrowing base again. So I think we look at certain situations where certain shorter transactions where that would improve our situation where it is at, but these are all on the table.
I think we just want to be careful in how we consider them and come out with the best strategy for the company.
Edward E. Cohen
And remember as Noel pointed out a little earlier we're primarily natural gas and the natural gas price environment has been quite stable. So we feel very good about where we are and where natural gas prices are vis-à-vis bank redeterminations and our future liquidity.
Sean Sneeden
Okay, that's helpful. And then maybe just as a followup as one of the previous questions, how do you guys kind of think about using capital with your unsecured bonds trading at 18% to 20% type of yields versus the drilling returns that you're getting in say at what point does this kind of directing capital towards bond repurchases begin to make sense?
Edward E. Cohen
I think it makes a lot of sense right now. The interesting thing is that there are so many opportunities that the present circumstances have offered that we do have to do a lot of thinking.
But the bond pricing and the opportunity there is quite attractive.
Sean Sneeden
Okay, great, I appreciate it. Thank you.
Edward E. Cohen
Thanks, Sean.
Operator
The next question comes from the line of Steven Carpo [ph] with Credit Suisse. Your line is now open.
Unidentified Analyst
Good morning.
Edward E. Cohen
Hi, Steve.
Unidentified Analyst
I didn’t follow the numbers so I apologize to understand about production between some of the downtime some of the new capital and then Arkoma. Can you give us a sense by product, I understood a bit on oil was going to be down sequentially but by product what Q3 and Q4 directionally looked like versus Q2?
Daniel Herz
Sure, this is Daniel. The direction I was trying to provide generally is that we would expect natural gas is we're not directing capital towards undeveloped natural gas locations to continue to decline in the third quarter and oil as we're directing capital and bringing wells on in our Eagle Ford Shale position per own account and per our partnership interest to flatten or be slightly down in the third quarter and then begin to rise in the fourth quarter and rise into 2016 as we bring additional wells on.
With respect to EBITDA I was generally guiding to flat third quarter versus the second quarter and then we would expect a significant rise in EBITDA in the fourth quarter.
Unidentified Analyst
And then there's been a lot of discussion on the call about deleveraging, can you be a bit more specific on, one what your goals are and then over the next call at six to nine months? And then secondly what kind of things can you do probably a resistance to use too much of the common units at this point, but what can you do to truly deleverage at the ARP level?
Edward E. Cohen
All right, I think Sean can answer for the goals, I'm not sure how much we can actually say about our specific discussion that may be taking place. Sean?
Sean McGrath
Sure, yes Steven. It is obviously two sides of the leverage equation, EBITDA and the debt.
I think when we look at our EBITDA I think as Daniel mentioned go through the drill bed and I think the wells that we taking a look at and plan for the second half of the year, I think our partnership program as Ed mentioned the budgeted number of $150 million I think, we had great success last year, I think we're looking at that that has very good potential in terms of this year and future years as Ed mentioned, just try and cut investment to all that it is and the good results we've had. I think with the cost reductions and Mark and his team as well as the G&A reductions, we see EBITDA as a growing metric over the periods of time.
And so it is hard to get into more details beyond that. I think on the debt side we continue to make sure that we're considering where the company is at and taking a look to make sure that we have good liquidity sources as well as the right opportunity is where we could look to bring down debt through structure transactions on the equity side.
But that being said, obviously the price right now is not where we want it to be, but I think we execute our plan I think, the answer is it will continue to trade better.
Unidentified Analyst
Maybe simplistically is it fair to say that you want some improvement, you are not scared to use the units to delever? And then how about using some of the cash flow associated with the units potentially the distribution to delever?
Edward E. Cohen
I think we're not scared of anything, but we have to evaluate all possibilities.
Unidentified Analyst
Thank you.
Edward E. Cohen
Operator
The next question comes from the line of Craig Shere with Tuohy Brothers. Your line is open.
Craig Shere
Good morning, guys.
Edward E. Cohen
Hi, Craig.
Craig Shere
Mark, how long does compression contracts begin to roll over and how large can the savings be and the 20% Eagle Ford IRRs was that based on some price tag or continuing to go strip pricing? And can you give us an update on those 20% IRRs given no M&A and static oil field service cost is how many years of drilling inventory do you think you have?
Mark Schumacher
Yes, on the compression, we continue to evaluate and consolidate we're going to see those starting to roll off in the next 30 days several had I'd say one to four months in sum, so we're going to see them tail off over the quarter. And then into the fourth quarter, as far as the number of compressors that is kind of fluid because we continue to evaluate and consolidate right now we're looking greater than 10 and significant cost savings.
We're looking at roughly I'd say $5000 to $8000 a month per unit. There is certain capital involved in returning units to the venders.
So sometimes there is a little bit of a payout to refurbish and engine for instance and we're going to see continued cost savings with regards to our compression and the terms. With regard to the Eagle Ford, I know as Daniel had mention we evaluate everything on a strip price.
As per vendor cost, and again I'll say it is a combination of working with our vendors, bidding, services, we do not have any long term agreements in place. So right now that's working to our advantage and the discussion with vendors along with our operational efficiencies.
We're ahead of the curve even to the AFE [ph] that we put forth in drilling these well right now. So we feel comfortable that we are going to see probably upwards of 40% or more cost savings compared to what was yesteryears development cost and the quality of the well per lateral foot is increasing because some of the steps the team has taken in hydraulic fracture stimulation design and also the targeting of these horizontal wells our geologic staff is doing an excellent job, kind of fine tune in the right rock to be in and our drilling department is doing an excellent job of executing on that plan.
Craig Shere
Yes, that fit a little bit in to the last part which is your inventory, you say you are targeting the right wells. So, given everything you just described how much inventory do inventory do you have?
Edward E. Cohen
ARP has an inventory right now approximately 50 locations and it would depend on how many rigs we choose to put to work, but right now we're drilling probably on average a well every, roughly three weeks. We're getting even better than that on our cycle time down the two weeks and in certain cases on multi-well pads.
We continue to look at additional opportunities out there, but right now the well count is around 50 economic development locations.
Craig Shere
That's very - go head.
Daniel Herz
And Craig, but this is Daniel, to put that in context, that's in the Eagle Ford that is two to three years of inventory which over the last 11.5 years is where we have averaged our inventory, back log, of course we have north of $1 billion, $1.5 billion of additional inventory elsewhere that becomes more and more attractive at different commodity prices. I should note that at very low costs we've been adding acreage in the Eagle Ford with that is on par with the returns that we're seeing there.
It is almost been given to us that we can take advantage of. So we're seeing great opportunities to continue to add to the Eagle Ford inventory by virtue of our pricings there.
Craig Shere
That's all very helpful. On HEP [ph] you let the $230 million closing, can you comment on your ability to not only have paid obviously for the acquisition you just made on that level and the structure.
But to actually have the resources to drill off $230 million to actually pay for the Eagle Ford actuation at the HEP [ph] level. But then to develop those properties may not be sufficient at the moment in total.
Can you discuss that?
Edward E. Cohen
Well, you have to remember it is a private company, but we can discuss it to some extent. It has met all of its obligations.
It has cash on hand to carry forward. It is a drilling program and I think the private investors and that company will be pleased with the results.
Craig Shere
Mark, I think last quarter you made reference to work-overs of 50 to 70% returns. I don’t remember much being discussed on this call.
Is that still part of the mix and much opportunity remaining there?
Mark Schumacher
The reference there was to the coalbed methane recompletion Raton and we executed on four of them and they were successful either package probably generated into 50 to 70%. There are additional opportunities.
That's an area northern part of New Mexico where we work with the surplus owner and kind of stage multiple recompletions at a time and so they are specific time during the year that we can do these recompletions. So we are continuing to look at him and it's just a competition for capital and which projects will bring us the best return, but there are more, yes.
Edward E. Cohen
Great, thanks. My last question, just want to clarify, how much did Arkoma contribute to the dropdown contributes to ARP production in the quarter.
Mark Schumacher
On a net basis we are raglan 10 mm a day net and the effective date was January 01.
Craig Shere
Okay great, thank you very much.
Edward E. Cohen
Thanks Craig.
Operator
And the last question comes from the line of Michael Cana [ph] with Angela Gordon [ph]. Your line is now open.
Unidentified Analyst
Hi, my couple of things, so first thing I'm looking at the CapEx and it looks like it is 26 some odd million, about 50/50 maintenance and growth CapEx. If we go back to Q1 to look at Q2, I think the production was about flat and I think the comment on the phone was Q3 perhaps flat to down before oil substantially increasing in Q4.
So how do you categorized maintenance CapEx because just a flat nature of production sequentially around the quarters would suggest that the total CapEx is actually in fact the maintenance. So you can just elaborate on that a little bit?
Edward E. Cohen
Daniel, if you like to comment on that.
Daniel Herz
I will and Sean can elaborate further if he feels appropriate. And I said that I discussed this many times before.
We can maintain our production by drilling on our position in Lycoming County or our Utica position but we're focused first and foremost on deriving returns. And to do that our best returning projects are in the Eagle Ford, that Mark has described our returns on a heads up basis which are even greater as we drill through the partnership business and substantially greater.
So, from our perspective, instead of simply trying to hold our gas equivalent volumes flat; we're trying to drive our margin higher and that's when we think about maintenance CapEx it is about maintaining our margin. It is not about maintaining our gas volumes because frankly we could that at a fraction of the cost that we're putting forward as far as maintenance CapEx.
Unidentified Analyst
Okay, I appreciate the answer. The second question is a followup on the whole liquidity issue.
So from where I sit back and I look at this at the ARP level your debt and your senior notes are trading south of $0.70 on the dollar and if you look at the equity of ARP and just on the dividend yield of units sort of seems to me the market there is substantial investors out there, just saying that they are not believing the current annual distribution is sustainable. So therefore, if that's the case what - I thought be perhaps temporarily or lower the distribution give yourself liquidity and with that additional amount either take advantage of the discount of the senior notes or paydown some additional revolver and give yourself some more liquidity on your borrowing, on your revolver because really who knows what banks are going to be thinking in terms of price deck come the fall.
And strange times basically call for unusual actions, not what you'd want to do, but it is, I'm not, it looks like how much of the penalty be on your units anyway in conjunction of the fact that at ATLS it is not as if there is a large fixed cost base that would need to be supported by the cash flow coming out from its AOP [ph] units are at holds. So could you just provide some thoughts on that?
Edward E. Cohen
Well, I think Michael you provided some very good thoughts and I'm sure that our board will be taking it all into considering. The nice thing is to be in a good position as we are to pick and choose how we move on our cash flow.
Unidentified Analyst
Okay, I appreciate it, thank you.
Edward E. Cohen
Thank you.
Operator
Thank you. I am showing not further questions.
I would now like to turn the call back to the Chief Executive Officer, Edward Cohen for any further remarks.
Edward E. Cohen
Well obviously given the length of this call you'll be relieved to know that I won't make any further remarks other than we hope that our next call will be under conditions which are better for the industry than the present conditions. Thank you all, bye-bye.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect.
Everyone have a great day.