Atlas Pipeline Holdings, L.P. Q3 2009 Earnings Call Transcript

Atlas Pipeline Holdings, L.P. (AHD)

Q3 2009 Earnings Call Transcript

November 4, 2009 9:00 am ET

Executives

Brian Begley – VP, IR

Gene Dubay – President and CEO

Glenn Powell – COO

Eric Kalamaras – CFO

Analysts

Helen Ryoo – Barclays Capital

Sharon Lui – Wells Fargo

John Tysseland – Citigroup

Lee Cooperman – Omega Advisors

Gregg Brody – JP Morgan

Brian Lively – Tudor Pickering, Holt

Kalinga Somasundaram [ph] – State Three Global Advisors [ph]

Presentation

Operator

Good day ladies and gentlemen and welcome to the third quarter 2009 Atlas Pipeline Partners earnings conference call. My name is Marisa and I will be your operator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of the conference. (Operator instructions).

I will now like to turn the presentation over to Mr. Brian Begley. Please Proceed, sir.

Brian Begley

Good morning, everyone, and thank you for joining us for today's earnings call. Before our management team provides comments on our third quarter results, I'd like to remind everyone of the following Safe Harbor provision.

During this conference call we make certain forward-looking statements. That is statements related to future not past events. 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,” “intends,” “believes,” and some more words or phrases.

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

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

Lastly, management’s presentation this morning includes references to such items as EBITDA and distributable cash flow, which represent non-GAAP measures. A reconciliation of these non-GAAP measures is provided in the financial tables of our third quarter earnings release, as well as our Form 10-Q.

With that I'll turn the call over to our Chief Executive Officer, Gene Dubay, for his remarks.

Gene Dubay

Thank you, Brian. Ladies and gentlemen, thank you for your time and your interest in Atlas Pipeline Partners. Today, I have with me in addition to Glenn Powell, our Chief Operating Officer, Eric Kalamaras, our new CFO. I will ask Eric to introduce himself shortly. I will say to all of you that I'm very pleased that Eric has joined the management team. And I believe we will all benefit from his expertise.

We continue to progress toward the goals we enumerated on our calls this year. We have, in fact, closed on the transactions we discussed in prior quarters. We renegotiated our bank covenants. We significantly reduced our G&A costs. And we establish core prices for much of our liquids production for the coming quarters using our hedging strategy.

Now, our focus is on the utilization of our plant capacity and gathering infrastructure and the optimization of opportunities within our core areas. In this third quarter we produced 56,400 barrels per day of NGLs and condensate, which represents a slight decline from 57,400 barrels per day we produced in the second quarter, a decline of less than 2%. This decline in production was a result of decline in gathered volumes across our Elk City and Chaney Dell systems.

However, since the close of the quarter, we've had that shortfall remedied. Atlas and a producer in Kansas have agreed in principle for Atlas to provide a pipeline connection and processing for the producer. Atlas will connect to the producer system which currently moves over 18 million a day. This connection would give the producer processing at the Atlas for NOARK processing plan.

The producer has over 70,000 acres help our production with approximately 200 crude developed locations and initial 140,000 acres under lease. As a consequence, we expect the volume under this agreement to grow significantly over the next couple of years. Even more importantly, we have begun receiving deliveries of gas that have been shut in behind our Elk City system of approximately 45 million per day.

A new well drilled in the Granite Wash, which came on in early October, now delivering 15 million a day into our western Oklahoma system. And we anticipate more from the Granite Wash in the future. The sum total of these volumes were remedied to decline that we have seen in our Chaney Dell and Elk City systems.

Much of the incremental gas volume which we were receiving as a higher Btu content with a greater liquids component and as a result we will continue to see our recoveries of crude on Mcf basis.

In this quarter, we expect to have the consolidator plant and west Texas completed and on line by the middle of November. We will begin to see an immediate increase in process gas and liquids production in West Texas.

We expect to see production of an incremental 3,200 barrels per day in West Texas by the end of the year. Our partner in west Texas, Pioneer, has announced they plan to drill 350 wells in 2010 and some 500 wells in 2011.

Although at Velma, we have not reached 100 million a day threshold that we expect to reach in this quarter. We have seen encouraging signs that one of our producers in this area may begin the completion process on a number of wells that were drilled early in the year. If these wells are completed in the near-term this plan maybe brought up to full capacity.

Our business in Appalachia has enormous upside. The Laurel Mountain partnership has only recently completed its infrastructure plan for the coming years, but we're excited by what has been proposed for the partnership build-out and by what have a synergy expects to develop.

Atlas Energy has stated that they intend to drill approximately 130 Marcellus wells in 2010. And they expect to expand that development significantly over the next couple of years. As a partner with Williams Companies we could not be more enthusiastic about our prospects in Appalachian.

In our field operations our goal is to beat the most efficient processed in the areas we operate and to maintain a significant core acreage position with our producer customers.

Our business continues to improve in what we all acknowledge has been a very difficult environment last year. Our challenge in the near-term is to complete initiatives that we have started to maximize the utilization of our plant capacity, manage our balance sheet and reduce our longer-term risk to the benefit of our equity owners.

We recognize that we have a Master Limited Partnership and as Master Limited Partnership we need to pay a distribution and we can sustain and grow. As management we're dedicated to initiating such a distribution as soon as is sustainable. Over time, we are targeting a leverage of four times, which by definition means we increase the EBITDA or reduce debt at current levels.

If we do use today’s price tag coupled with a 55% NGL to crude correlation we get over the EBITDA very quickly. However, we do not control prices. What we can do is work to build the volume across our system and hedge our prices where we have the opportunities so that we reach our EBITDA potential as quickly as possible. Again, I appreciate your time. We are pleased to have you with us as investors and look forward to working with you and on your behalf.

With that I will turn this call over to our Chief Operating Officer, Glenn Powell. Thank you.

Glenn Powell

Thank you, Gene. The third quarter was one of continued growth in commodity prices and steady operations across all of our business units. The success from running our assets is efficiently and is reliably as possible allowed us to transport approximately 833 million cubic feet of natural gas per day and produce about 53,000 barrels per day of NGLs and 3m300 barrels per day of condensate.

We connected 81 wells into our gathering systems during the quarter. At our Chaney Dell system, we gathered approximately 269 million per day in the third quarter, down 3% from the prior quarter. NGL production was 13,400 barrels per day, down 2% for the second quarter of this year. And Condensate production was 750 barrels per day in line with the prior year. A total of 14 new wells were connected to the system during the third quarter.

As Gene mentioned, Atlas and a producer in Kansas have agreed in principle for Atlas to provide processing in a pipeline connection for the producer to the Chaney Dell system. The producer has over 70,000 acreage held by production and an additional 140,000 acreage under lease.

The producer system currently moves over 18 million per day and the producer plans to drill 120 wells over the next five years. This new gas will help Atlas to continue to grow its business in western Oklahoma and Kansas.

At our Elk City/Sweetwater System we moved volumes of approximately 211 million per day, a 4.5% decrease from the prior quarter. And we produce an average of about 10,800 barrels per day of NGLs.

In response to low natural gas prices producers on the system continue to shut in production during the third quarter. As Gene mentioned in his comments we have seen the majority of this volume approximately 45 million per day come back on the system for the November production month. Eight wells were connected into the system during this quarter. This does not include the connection associated with the approximately 15 million per day Granite Wash well that Gene referenced which began flowing into our system in October.

On our Midkiff/Benedum system, gathered volumes increased to a 166 million per day, a 3% increase over the prior quarter. Our NGL production was 19,900 barrels per day, down 3% from the prior quarter. The decrease in NGL production was related to a drop in ethane recoveries at our Midkiff plant. The (inaudible) recovered ethane barrels were sold as natural gas residue production resulting in a 6% increase over the prior quarter.

As you may remember the consolidator plant currently being constructed will replace the MidKiff plant and will result in an increase in liquids recoveries. Condensate production totaled approximately 2,000 barrels per day in the third quarter, a 26% increase over the third quarter production in the prior year. The Midkiff/Benedum system also completed a total of three new well connects in the third quarter.

Within our Velma system, we gathered approximately 82 million per day, a 2% increase over the second quarter. We recovered 8,900 barrels per day of NGLs, which is a 5% increase over the second quarter, and a 35% increase from the third quarter of 2008. Condensate production was approximately 380 million barrels per day. From a commercial standpoint, there were three wells connected to the system during this quarter.

The construction of our previously announced Nine Mile plant which is situated on the Slider pipeline between the Elk City and Chaney Dell systems is complete. As mentioned in our July press release, we have completed the sale of our 60 million per day Sweetwater II processing facility to Penn Virginia resources. Based upon our volume assumptions and in order to meet our processing capacity requirements we expect to restart the Nine Mile plant in the fourth quarter.

At our Midkiff/Benedum system, the construction of our 150 million per day consolidator cryo plant continues to move forward. The construction of this plant will increase NGL recoveries lower ongoing maintenance capital requirements and also provide us with an additional 40 million per day of processing capacity on that system.

We anticipate this project to be completed in the fourth quarter of 2009 and we are optimistic on the success of this project based upon the publicly announced drilling plans of the producers on this system. The two largest producers have announced to drill over 500 wells in 2010 and over 800 wells in 2011.

The Laurel Mountain gathering system had throughput of approximately 106 million per day in the third quarter, 14 million per day over the third quarter of 2008. Laurel Mountain added 53 new well connections in the third quarter. Laurel Mountain plans to return two gas processing plants in Washington County to service in November.

Atlas Energy currently has three horizontal Marcellus Shale wells and six vertical Marcellus Shale wells shut-in behind these plants. Atlas Energy has also drilled and cased five additional horizontal wells that were delivering into these plants as they are waiting to be fracked [ph].

To address the pressure issues on LMM’s legacy gathering system in Southwestern Pennsylvania, Laurel Mountain has initiated three significant looping projects in Green and Fayette counties which are expected to add approximately 30 million per day in the second quarter of 2010.

In summary, we experienced improvements in operations and commodity prices in the third quarter, and we remain focused on addressing the challenges created by the economic recession.

With the completion of the Laurel Mountain infrastructure plan we are looking forward to the partnership build-out and Atlas Energy’s plan to drill 130 horizontal and vertical Marcellus Shale wells in 2010.

We are also excited about the future drilling plans of Pioneer and the other producers in the west Texas, which coincide with the completion of our consolidator plant in the fourth quarter.

We are pleased with the growth at our Velma asset and for the opportunity to continue to expand our western Oklahoma gathering systems into the Granite Wash reservoir and further in the Kansas. We are optimistic that by remaining flexible in our capital spending plans and aggressively pursuing operational efficiencies we will continue to achieve great success.

And at this point I will turn the call over to our Chief Financial Officer, Eric Kalamaras.

Eric Kalamaras

Thanks, Glenn. I would also like to thank everyone for joining the call this morning. I also like to say how delighted I am to be here at Atlas. After having worked with the team for several years and is the company of wonderful people and a strategically positioned asset base. I also knew there would be a thrift opportunity to upgrade value for our stakeholders and look forward to working with Gene and the rest of the management team in doing that.

With that let me move into the quarterly results. The partnership quarter, third quarter 2009 adjusted EBITDA of $29.3 million versus $80.7 million in the third quarter of last year. Included in adjusted EBITDA for the third quarter of 2009 was $19 million realized cash loss from commodity positions. Primarily from the settlement of legacy natural gas swaps, as well as a $1.5 million gain in the sale of our Sweetwater II processing facility. This gain is partially offset by post-closing adjustment of our Appalachian interest.

Excluding those two items our recurring adjusted EBITDA was 46.9 million. And because we had a significant amount changed our asset base since the beginning of the year. I thought it would be helpful, but our recurring adjusted EBITDA in the context, pro forma for the sales of NOARK, partial interest in Appalachia, Sweetwater II, adjusting for the legacy commodity settlements, recurring adjusted EBITDA net of all those events was $37.4 million and $39.5 million for the first and second quarters of 2009 respectively.

So this quarter's 21% increase recurring EBITDA versus second quarter and a 27% increase since the start of the year is quite favorable even as very low natural gas prices significantly curtailed producer activity.

Discussing recurring cash flow of the business is a good segue into our hedging program. And we remained very focus on managing the risks associated with commodity price exposure and to meet our deleveraging objectives.

Consistent with the strategy we have taken advantage of the forward curve and enter into new hedge positions for our liquids production. We're now approximately 63% hedged for the remainder of 2009, approximately 40% hedged for the first half of 2010.

We've opportunistically add to our hedge positions to further protect our cash flow. Going forward, our strategy is to be up to 80% hedged, our liquids production during the current year are continuing to layer in protection in the out years. As a reminder, we are currently using products at specific options and only using crude oil to protect the heavy end of the NGL stream.

We've included in our press release a quarterly summary of our existing hedge positions. Regarding the legacy commodity positions, which comprise most of the natural gas swaps, as previously stated, we were negatively impacted by $19 million during the quarter. More recently, as the spot on natural gas prices increased and the forward curve improved, our notional future exposure to swaps has declined. Any additional forward movement prices will reduce the cash impact of the settlements.

We are actively seeing to take out a substantial portion of the swaps prior to maturity. We will do so as opportunities present themselves. As a reminder, these positions biometrically declined in the first quarter of 2010 and completely run-off during the second quarter of 2010.

Our adjusted gross margin per Mcf of process gas in the quarter was $0.75 versus last year of a $1.32 when commodity prices were coming off their historic highs. Compared to the second quarter of 2009, our adjusted gross margin increased 47%. This marked increase is the result of higher NGL prices in a declining natural gas price environment.

Realized NGL prices compared to the second quarter increased 12% to $0.75 a gallon. So we are seeing sequential quarter price improvement. Importantly, since the end of the quarter, not only have we seen sharp movements in NGL prices, but also strong movement in the NGL crude ratio as ethane, in particular, has been trading strong on a relative basis.

Crude oil appears to have price in recovery of industrial demand is coupled with its higher relative cost compared to the natural gas. NGLs have been trading at a more favorable basis.

Puts in the context, the NGL, the crude ratio was 46% in the third quarter is now near 55%. As a result, we are experiencing a significant cash flow improvement from just a few weeks ago.

From a G&A standpoint, we continue to see the beneficial impact of expense reduction initiatives that were taken over the past several months. For the quarter, G&A net of non-cash compensation expense totaled $8.7 million compared to $10.6 million net of non-cash compensation expense in the third quarter of last year.

For reference, third quarter 2008 contained a $13.3 million credit in a changed non-cash based compensation plan. So on an apples-to-apples basis G&A is better by $1.9 million versus last year.

Cash interest expense net of normally deferred financing costs totaled $26.5 million versus $21.1 million last year. The increase is due to higher LIBOR on a floating rate debt and changes in our credit facility, although this is partially offset by $183 million reduction in total debt. We have interest rate swaps that expire on both January and April of 2010, and the swaps roll-off we expect to see further improvement in our interest expense.

Regarding liquidity, we continue to carefully manage our balance sheet and maintain a cushion on our bank covenants. We are executing a number of transactions in this year that have significantly strengthened our liquidity position. During the third quarter, partnership issued 2.7 million common units, generating $16 million and coupled with 22.6 million proceeds in the sale of our Sweetwater II plant, we reduced the outstanding balance and our senior secured revolving credit facility and term loan by 38 million.

This reduced debt to 1.24 billion. And our debt portion of the capital structure is comprised of following

$315 million of revolver borrowings are maturing in July 2013; $434 million of term loan maturing in July 2014; and $495 million of unsecured notes maturing in 2015 and 2018.

We ended the quarter with $740 million in Partners' capital. For the third quarter our total leverage was 4.1 times; senior secured leverage 2.5 times; interest coverage 3.3 times; debt to capital 61%.

At September 30, we have $56 million in capacity available under our $380 million revolver, giving effect to outstanding borrowings $350 million and $9 million leverage of credit. We also had $5 million cash on hand. With revolver availability was a total liquidity at the end of the quarter to approximately $61 million.

Turning to capital expenditures, we invested $5.6 million in growth capital projects and 1.5 million in sustaining capital expenditures in the quarter. This is down significantly from both prior period as well as second quarter of 2009, both our capital spending was front end loaded this year.

The majority of the capital spend in the third quarter is for the consolidator plant scheduled to start in next few weeks. In the fourth quarter, we expect our capital spending to be approximately $15 million, the bulk of which is related to consolidator and well connects and west Texas system to develop (inaudible) trend.

And in summary, we continue to focus on our three key priorities. Deleveraging the balance sheet, derisking cash flows, both physically and financially, and achieving operational efficiencies to our assets.

With that let me turn the call over to moderator for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions). And our first question comes from the line of Helen Ryoo from Barclays Capital. Please proceed.

Helen Ryoo -- Barclays Capital

Good morning. Thank you. My first question is your EBITDA of 37 million that included 19 million of realized hedge losses and then your adjusted EBITDA of 29 million had 6.7 million of noncash derivative expense. So, in total did you have a hedge impact of 25.7 million in the third quarter? Is that the right way to look at it?

Eric Kalamaras

No, it’s not. Helen, this is Eric Kalamaras. We'd a total cash impact of $19 million for the quarter, primarily comprised of $14 million of the gas swaps and there is another residual portion of NGL some legacy commodity unwind.

Helen Ryoo -- Barclays Capital

Okay, then what is that 6.7 million non-cash derivative expense?

Eric Kalamaras

We're checking for you. While we're looking do you have another question?

Helen Ryoo -- Barclays Capital

Yes, and then another question is just about your Appalachian build-out. With the drilling program going on with the key producers behind your system how much gathering pipeline capacity is currently being built out and what is your expectations for next year? Also, how much capital is required to do that? And how much is APL allowed to spend up there based on your credit agreement. My understanding is about 10 million per year in north Marcellus. But you also have 25 million note with WNB, so, just wanted to see how much you could spend up there given everything going on?

Gene Dubay

Sure, I'll take the latter part of that. With the $25.5 million note effectively amortized over three years the credit agreement provides for $10 million carve out for Laurel Mountain, so coupled with the notes that will give you roughly another $8 million a year. So $18 million is the effective capital spending under the credit agreement as we stand today.

Helen Ryoo -- Barclays Capital

Okay. For next year?

Gene Dubay

Correct.

Helen Ryoo -- Barclays Capital

And does that include the $25 million from WNB?

Glenn Powell

Yes, this change maybe, $25 million is the note which we get eight year in amortization, because that note is already starting to amortize, we get closer to 16 in turn to that amortization. So our number that we can deliver to the partnership per our share without any other participations closer to around $26 million for the term of next year.

Helen Ryoo -- Barclays Capital

Okay, great. And about the capacity build out on your gathering pipeline up there?

Gene Dubay

I've much capacity. The partnership expects to build out the capacity that the Atlas Energy needs to deliver on their production. So in this capacity is being built out in a number of areas, but we will expect to add 100 million over the course of perhaps the next 18 months, 100 million a day in capacity.

Glenn Powell

There are 16 specific projects and three of them have to do with just looping the legacy system. And we feel like based on the plans that we worked out with our partner, Williams, that we're putting ourselves in a good position to be able to handle the drilling of Atlas Energy next year.

Helen Ryoo -- Barclays Capital

Okay, great. And then I guess my last question is given all these new volume that you expect to come into your system that you talked about in the prepared remarks do you expect your equity NGL volumes to be higher than what you had at the starting of this year. What is your expectation for next year, you could throw that?

Glenn Powell

We’re very excited obviously with the growth in the Appalachian system with Atlas Energy in being able to build up a system with Williams. And so obviously we expect to see some improvement there and then obviously we are excited about what’s happening with Pioneer and the other significant players at our west Texas system, increase in drilling significantly to the range of about 500 plus wells just amongst the top two producers.

So we're expecting to see some growth and we're expecting to see an ability to be able to fill up our new added capacity that we've added with our consolidator plant in west Texas. And then our expansion in the Kansas, we feel it’s a very strategic and we feel like we're in good position to be able to bring that gas into our western Oklahoma system, where we have available capacity, and then also to help fill up that available capacity is being able to participate in the Granite Wash growth. So we do see some improvement, we see producers looking forward to 2010, we are seeing a lot of producers very focused on Ritchett [ph] gas place, that’s where our liquids barrels continue to grow so we are looking at some improvement next year.

Eric Kalamaras

And Helen, this is Eric Kalamaras. Just going back into your question regarding the $6.7 million that is a non-cash mark-to-market gain, so the cash portion is the $90 million.

Helen Ryoo -- Barclays Capital

Okay, great, thank you.

Eric Kalamaras

So the 12 you’re referencing is close to the difference between the two.

Helen Ryoo -- Barclays Capital

Okay, thank you.

Gene Dubay

You're welcome.

Operator

And our next question comes from the line of Sharon Lui from Wells Fargo. Please proceed.

Sharon Lui -- Wells Fargo

Hi, good morning.

Gene Dubay

Hi, Sharon

Sharon Lui -- Wells Fargo

Just following up on Helen’s question about Laurel Mountain, so I guess the plan is to spend $18 million for Atlas, I was just wondering what's the total capital spend for the JV.

Gene Dubay

Well I think what I have said -- this is Gene Dubay that when you take that we really have because NOARK started amortized in April last year we come closer to $26 million for what we can spend. The JV will spend more than that, I mean it depends on the timing, but so we have build out plan, but right away it needs to be acquired and that plan may likely be spent more over 18 months or 24 months than the 12 month period that we're looking at. But JV will have a number higher than 52 which if you take out 26 and double it will be to that number will be higher.

Sharon Lui -- Wells Fargo

Okay, so I guess is it safe to assume I guess is your interest in the JV to decline over 2010?

Gene Dubay

No, I think we are looking at ways that we can stay up with that, maintain our participation, so we will have more to talk about as this develops.

Eric Kalamaras

Hi, Sharon this is Eric Kalamaras. The one thing I would also comment is that we have not seen a capital budget yet also, and further we have not had any capital calls on our 2009 portion either.

Sharon Lui -- Wells Fargo

Okay. And the 2009 portion you can roll over to 2010?

Eric Kalamaras

No, I am just no, we can't, I am just thinking just trying to get to think in terms of we just don’t have a capital number to work with, just in the context yet

Sharon Lui -- Wells Fargo

I guess moving on to West Oak [ph] and the new contract with the producer, is there any capital requirement associated with bringing on that gas?

Glenn Powell

Yes, yes there are, and its approximately $12 million for us to connect into their system and bring that gas back to us, and so we have already bought a significant portion of that right away and we hope to have that volume into our facility sometime in the Q1 next year.

Sharon Lui -- Wells Fargo

And I guess in terms of the contract with the producer are you processing for fee or how does it work?

Glenn Powell

It’s a percentage proceeds contract.

Sharon Lui -- Wells Fargo

And I guess just looking at coverage ratio and the main statement of the distribution have you guys thought about what's an appropriate coverage ratio that you guys will achieve?

Glenn Powell

Sure, Sharon, I think the right contacts in that will be approximately one and half times. And just going back thinking about your question the $8.5 million as it relates to the preferred that is the portion that we can roll over versus relates to Laurel Mountain.

Sharon Lui -- Wells Fargo

Okay, so…

Glenn Powell

Does that help?

Sharon Lui -- Wells Fargo

Yes that does help.

Glenn Powell

Okay.

Sharon Lui -- Wells Fargo

Okay, thank you.

Operator

Our next question comes from the line of John Tysseland from Citigroup. Please proceed.

John Tysseland – Citigroup

Hi, guys, good morning. Quick question on the hedge losses. We had anticipated I think somewhere around 11.6 million losses given where the volume prices came in, you guys came in at 19, did you accelerate any losses during the quarter, in other words, should we expect fewer losses over the next couple of quarters on your legacy hedge positions?

Eric Kalamaras

Hi, John, this is Eric Kalamaras. I think the way to think about the loss is going forward part of as a function of natural gas prices really flow it right towards the end of the quarter so the kind of a bigger impact there so is that portion comes up, we will expect to realize fewer losses. As far as actually accelerating and taking out anything any additional swaps we typically would take those out towards the end of the month, but we’ve not accelerated anything meaningful, in terms of 2010 positions.

John Tysseland – Citigroup

So the best way to look at it not necessarily average price for the quarter that impacted those hedging losses more or less where the contracts ended up at the end of the quarter, is that fair?

Eric Kalamaras

That’s right.

John Tysseland – Citigroup

Okay, and then what would you currently expect if you look at Q4 and the pricing on legacy hedge losses in the Q4, natural gas prices stay in $4.50 to $5 range I mean we can calculate and guess but just from a management perspective what is your view?

Eric Kalamaras

We were to think about the total forward value right now, it's approximately $17 million in aggregate for all of 2010 and for the rest of 2009. So it’s come out meaningfully.

John Tysseland – Citigroup

No, I am saying, what is the number, what is your expected loss?

Eric Kalamaras

For the Q4?

John Tysseland – Citigroup

Yes.

Eric Kalamaras

We can get back to you on that.

John Tysseland – Citigroup

Okay, fair enough. And then also on the TNF [ph] cost, can you just discuss what you're seeing now and the services versus last year sequentially. I think we discussed around $0.05 a gallon. Is that a good number to use going forward or you see cost creep on that given I guess current utilization rate?

Glenn Powell

Hi, John, this is Glenn Powell. Most of our contracts on the liquid side are termed up long-term, we had one contract that we had to renegotiate at our ONEOK plant, so we did see an increase in the fee there, but your estimate is pretty accurate still.

John Tysseland – Citigroup

Okay, and then lastly the leverage ratio is that you discussed, is that in line with how the banks look at your leverage ratios and coverages or is that calculated slightly differently?

Eric Kalamaras

No, those are based up our adjusted EBITDA number, which reconcile with the formulas outlined in the credit facility.

John Tysseland – Citigroup

Okay, great, thank you.

Eric Kalamaras

You’re welcome.

Operator

And our next question comes from the line of Lee Cooperman from Omega Advisors. Please proceed

Lee Cooperman -- Omega Advisors

Yes, thank you, good morning. Two questions. When you talk about a target leverage ratio of 4:1, I assume that leverage ratio you're looking at is you're basically debt to EBITDA, and is that a correct assumption?

Glenn Powell

Yes.

Lee Cooperman -- Omega Advisors

Right. Do you anticipate that you would get there without raising equity capital just to internal cash flow possible asset sales or do you think that raising additional equity will be part of your program?

Gene Dubay

We can get there without an equity raise.

Lee Cooperman -- Omega Advisors

Good and secondly do you anticipate over the next 12 months that remaining or within your covenant requirements and the covenants will be triggered?

Gene Dubay

Yes.

Lee Cooperman -- Omega Advisors

Thank you very much.

Operator

And our next question comes from the line of Gregg Brody from JP Morgan. Please proceed

Gene Dubay

Gregg, are you there?

Gregg Brody -- JP Morgan

Yes, sorry about that I was on mute. Good morning. Most of my questions have been asked. Just with respect to the debt EBITDA target you've given do you also have a liquidity target, which you think is to a minimum level?

Eric Kalamaras

The credit remain states a minimum level for distribution of $50 million, that being said, I think we would prefer to be higher than that. I don’t know there’s a specific number we have in mind, but something higher than $50 million would be a comfort level.

Gregg Brody -- JP Morgan

Just as you think about next year when you weigh the ability to reinstitute the dividend in the reimbursement business what's your comfort level of being able to reinstitute dividend and to the sense of timing?

Gene Dubay

This is Gene Dubay. I don't want to speculate on that. We as a management team want to do, very focused in recognize it our shareholders, unit holders, live with this through this straw, need to see the cash flow that we can generate as soon as possible, but we also recognize the distribution needs to be sustainable, we can start it and stop it, we have to have a plan to de-leverage as we're initiating the distribution and again with the price tag that we have today, forward looks pretty good for us, if we have the correlation tighten we're in great shape.

But again we don’t control prices, we're just going to manage our business as well as we can. And we have this legacy commodity position so we talked about this call that continued to harm us. So those legacy positions come up in the middle of the next year, prices are looking good, so, we are optimistic but I don't want to put a time on that.

Gregg Brody -- JP Morgan

That’s helpful and just congratulations for the transition.

Glenn Powell

Thanks, Gregg.

Operator

And our next question comes from the line of Brian Lively from Tudor Pickering, Holt. Please proceed.

Brian Lively -- Tudor Pickering, Holt

Good morning, guys. Just a quick question on your comments regarding your Pioneer partnership and 300 wells to 500 wells plan to be drilled over the next two years. I think last night Pioneer mentioned that they were planning to drill 425 Spraberry wells in 2010 and around 700 wells in 2011. Just thinking through that ramp and that accelerated activity, how would that impact your guidance going forward for that area?

Glenn Powell

Your numbers are exactly what our numbers are. That’s exactly right. Thankfully, we have a lot of infrastructure out there right now and so just looking at it obviously we don’t have their full well plan, we got predominantly through the first of the year, but we like what we see as far as where they're drilling in based on the infrastructure that we have we feel good about the growth there.

We're continuing to look at our guidance in the next year, but we haven’t finalized that, we haven’t finalized our budget yet, because we continue to work with Pioneer predominantly on making sure that we've got all the capital on the right places and obviously, working on the growth capital there we have in western Oklahoma and in Appalachia, so we don’t have anything as far as guidance going forward, but we are excited about all those drilling plans

Brian Lively -- Tudor Pickering, Holt

Okay, I appreciate that. And just maybe a follow up of kind of amore broad type question. What kind of the activity levels in west Texas, in general? Do you guys have a sense of how process and capacity is going to expand going forward in the Permean basin?

Glenn Powell

We like the position that we're in, because we’ve gone from one of the least efficient processors with our Midkiff facility to the most of efficient and so we like the position that we're in both from the gas side and then also from the liquid side, because we entered into a firm contract with Tapco [ph] to be able to take the liquids away, so again we think we're in a position to be able to grow as we take out our existing Midkiff facility, which is made up the three trains [ph] if we need to we can continue to leave one of the trains in place if we outgrow this additional 40 million per day of capacity so again we like where we are.

Brian Lively -- Tudor Pickering, Holt

All right, that’s great, thanks for the time.

Operator

And our next question comes from the line of Kalinga Somasundaram [ph] from State Three Global Advisors [ph]. Please proceed

Kalinga Somasundaram -- State Three Global Advisors

Thank you. Hi, Eric. My question is this. As you look in 2010 and you are going to be restating your distribution, if you choose at a later date to not reinstate the dividend or will you get any violation or how should say, how long could you not pay a dividend or a distribution and be in compliance with any IRS guidelines or any agreements you have in your partnership contract?

Eric Kalamaras

Hi, Kali, good morning. The answer for question is there is no obligation to do that, it’s effectively a tax issue as to where our income comes from and whether or not the income itself is qualifying. So that is really the stipulation that we work here, and that’s where we have to go by from the IRS tax code.

Kalinga Somasundaram -- State Three Global Advisors

Okay, thanks, Eric.

Eric Kalamaras

Thanks

Operator

This concludes the question and answer session for today’s conference. Now I would like to hand the presentation over to Gene Dubay for any closing remarks.

Gene Dubay

We appreciate your participation. Thank you very much. We look forward to working with you

Operator

Think you for your participation in today’s conference. This concludes the presentation. You may now disconnect and have a great day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: [e-mail]. Thank you!