Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Floyd Wilson - Chairman, President and CEO

Mark Mize - EVP, CFO and Treasurer

Dick Stoneburner - EVP and COO

Analysts

Jason Gammel - Macquarie

Michael Hall - Stifel Nicolaus

Ben Dell - Bernstein

Leo Mariani - RBC

Chris Pikul - Morgan Keegan

Ron Mills - Johnson Rice & Company LLC

Adrel Askew [ph] - Hartford Investment Management

Adam Leight - RBC

Subash Chandra - Jefferies

Beau Batner [ph]

Petrohawk Energy Corporation (HK) Q2 2009 Earnings Call Transcript August 5, 2009 9:00 AM ET

Operator

Good morning. My name is Christy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Petrohawk Energy Corporation Second Quarter 2009 Earnings Conference Call. All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer session. (Operator instructions) Thank you.

Mr. Floyd Wilson, you may begin.

Floyd Wilson

Good morning everyone, and thanks for joining. This conference call may contain forward-looking statements intended to be covered by the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of this disclaimer, see our press release issued yesterday and posted to our website, as well as our other public filings.

In addition to the second-quarter earnings release, our company issued a press release yesterday, relating to an equity offering that we are currently conducting. We are not at liberty to discuss the subject matter of that release at this call.

We have had a fine second quarter and first half of 2008, and I am pleased to report to you on it today, I am especially happy to report record production rate for the quarter of 483 Mcf per day that represents really, it continued strong growth for the Company.

On the macro side of things, as always there are competing views on natural gas supply and demand. We have worked hard to build Petrohawk’s so as to perform well during good times and bad. And I believe we have had some success along these lines. In addition, to having some great properties, we have always had the view that cost structure is particularly important.

We do subscribe to the concept of the haves and have-nots that some on our industry, but to us the haves relate to both the high-growth assets and low cost structure. These shale plays and our awesome staff provide both for us. We are do not part to replace US natural gas production with low-cost, low-risk, production from these important shale plays.

After more than a year of drilling in the Haynesville Shale, early perceived risk have not materialized, we have not run out of rigs, water, pipe, property, transport capacity, or people. We have kept pace with our least capital requirements and infrastructure needs and our wells are going on production fast.

The Haynesville Shale has surely become the king of shale’s. Another important advancement in the past year in the Haynesville has been our data mining and our intense geologic evaluation of the entire trend. Our own drilling, as well as the evaluation of the results of others who have led us – what we believe is the superior or an excellent understanding of the shape in composition of the Haynesville Shale.

Our Haynesville database is certainly one of the most complete in the industry. Importantly, our view of the data and drilling results leads us to better understand the plays extension into what I would call Central East Texas, the area in and around Nacadoches and Shelby Counties in East Texas has been the focus of intense leasing activity or on out part and others during the past several months.

This has been an aggressive – there has been an aggressive push among several prominent shale players to obtain new foot holes and what may become a new core area of the play. It is too early to declare that, but we have been working hard in this area. Our new leasehold is expensive and we have high hopes down here.

Early results have been encouraging and we intend to continue to define and evaluate this highly perspective extension and define with the drill bit. In Northwest Louisiana, as also been a concentrated push by several companies to mop up the last few remaining leases that were missed in 2008.

We have been successful of this, in fact having already drilled or started 25 wells on our new leasehold that we have acquired this year in the heart of the play. While this new wave of leasing pales in comparison to the land grab of 2008, which is notable to Petrohawk because of the quality of our new acreages additions.

Another ongoing important activity in our combined evaluation of the Eagle Fort Shale in South Texas – that is another important activity. We have taken what we have learned at Hawkville, our discovery in South Texas, which ignited the entire Eagle Fort Shale play, you know began to evaluate other areas in that region that looked to us to be perspective.

More on that from Dick in a minute. Anyone that has followed Petrohawk knows that our business view is a multi-year view and conservative financial view that supports our expansion in existing and new areas, our priorities are significant production growth and reserve growth, paid with low operating costs, or active hedging program and our ever present attempt and successful I should say to gain technical advantages and efficiencies, which improve over time in these large scale resource plays.

We expect what is good to get even better and we're conservative managers of our capital structure. I will turn the call now over to Mark Mize to discuss our financial performance.

Mark Mize

Okay, thank you, Floyd. We have a busy day ahead of us; I will keep my comments pretty brief and focused on the second quarter results. The operational and financial results of HK continue to show positive momentum and have clearly taken the way for solid feature for the company and its shareholders.

We did in the quarter with strong liquidity position and anticipate continued improvement as we began the redetermination of our borrowing base, not only on our E&P properties, but for Hawkville services as well.

We have finished the second quarter with a debt-to-total capital ratio, excluding the recent impairment of approximately 35% and we have an as reported ratio of 47%. Our production came in significantly over the high-end of guidance to 483 million a day, with about 94% of that being natural gas.

Natural gas price realizations, excluding the impact of hedges came in at 94% in IMAX, which is in line with guidance and is also an improved when compared to realization of 89% in Q1 of this year.

Now we continue to do our best to keep up, Dicks proved, from a production perspective to stay about 70% hedged of our anticipated production and if you consider the $2.34 per Mcf that we be picked up through the hedging program, we had a realized gas price right at $5.62, of which does have some part of an unprecedented tap on the funding of a capital program, not to mention the impact that it has on the upcoming revolver redetermination.

Looking to the cost structure LOE for the second quarter, came in at 43% per Mcf, which is to spend before the upper end of guidance. We do reaffirm our projected LOE for Mcfe for 2009 to be $0.36 to $0.44 per Mcfe, which does represent a 30% cost production when compared to 2008 guidance.

Taxes income came in at 29% per Mcfe, which is under the low end of guidance, however we do expect this metrics to be within guidance by year-end just simply due to the increase in Louisiana severance taxes that actually went to affect last month.

Gathering transportation and other came in at $0.53 per Mcfe, which has a slight improvement over Q1, which was at $0.55, but it is still over the high-end of the guidance. The initial expenses incurred are related to Hawkville services activities and we do expect this metric to remain over the high-end of the guidance throughout the remainder of the year.

G&A came in at $0.46 per Mcfe, excluding the impact of non-cash stock-based compensation and this is in line with the mid-quarter guidance on a fairly dramatic result considering the ’08 full-year metrics of $0.56 per Mcfe.

This quarter, our hedged mark-to-market was some part of a sizable number coming in with a non-cash loss of $85 million, well it is nice to have the downsized protection of our hedged program, our hedges are unfortunately paying of, you know the proceeds, HK of just under 100 million in the current quarter and a 180 million in the first half of the year.

As has always been the case, the unrealized non-cash portion of this item has been removed in our selected item stable that can be found in the press release. With regard to cash taxes, we expect to incur an ANT tax liability of approximately $24 million.

We have already received or expect to receive refund from a significant amount of previously paid taxes and we had mentioned this also in the Q1 earnings call, which will put us at a net cash payment position of about $2 million by the end of the year. And our effective tax rate for the quarter did come in at 38%, which fell low in the guidance.

With that I will turn the call back over to Floyd and Dick.

Dick Stoneburner

Thanks, Mark. The second quarter has been one of the truly outstanding quarters in the history of the Company, particularly as it relates to the operational success that it has been achieved. All three of our core resource plays have contributed to our outstanding growth this quarter.

In the Haynesville, we averaged operating ten horizontal rigs, drilled 13 operated wells and 19 non-operated wells during the quarter and increased production in the field, 63% from 114 million a day to 186 million a day. In the Fayetteville, we averaged two operated rigs and drilling only ten operated horizontal wells. However, we had 68 non-operated wells drilled, which help grow production 16% from 68 million a day to 79 million a day.

In the Eagle Ford, we operated two horizontal rigs, drilled six operated wells, and one non-operated well, and put three of the operated wells on production, resulting in 140% increase in production from 5 million a day to 12 million a day. I think it is appropriate to begin with a discussion of the Haynesville results, since it is a recipient of the majority of our capital and is driving the vast majority of the production reserve growth.

In discussing the success that Petrohawk has been able to achieve, I believe one word best describes our results and I believe that word is consistency. Through the end of the second quarter, the Company has put a total of 39 wells on production, which is excluding to mechanically compromised wells.

Ten of those wells were put on production in 2008 with an average IP rate of 20.3 million a day. 15 were put on in the first quarter of 2009 with an average IP rate of 17.0 million a day, and 14 were put on production in the second quarter of 2009, with an average IP rate of 17.3 million a day.

Additionally, Petrohawk has been very consistent in the reporting of these IP rates, which were based on the 24 hour period during which the well achieves its maximum production in most cases on 24/64" choke. For the last year or so the Company has been reporting these results it has felt that if the IP rate has been the most useful parameter of tracking and comparing wells, since we have such a limited database of wells with significant production history.

However, we now believe that there is sufficient data to discuss the average 30 day rate, as well as producing a collective time zero plot of all the wells referenced in this discussion. The Company now has at least 30 days of production from 38 of the wells referenced above, with the average first 30 days of production being 14.2 m a day.

The Company has also posted a time zero plot of all these wells at the Company’s website. As a means of explanation, this graph contains a decline curve of 40 of our 44 completions, which only excludes two wells for mechanical issues and two wells that have less than two weeks worth of production.

Each wells decline curve is initiated at the same point on the graph, which allows each well to be compared to the others, as if they all went on production at the same time. Super imposed within this data said, is the 7.5 Bcf type curve that we believe best represents the trend of these data.

The Company believes that the data available today, strongly supports the assumption that the average EUR in the acreage that Petrohawk intends to develop is 7.5 Bcfe and that the amount of data is more than sufficient to support this contention. While we now have a large enough sample set of well that has discontinued the reference of individual well results there are a couple of wells that I would like to make note of.

One is the Sample 4, Number 2 in section 4 of township 14 north, 11 west. This well completed in mid-March has already produced 2.3 Bcf, is still producing almost 13 million a day and has an EUR in the 13 to 15 Bcf range.

Another well of note is the Mathew 17, Number 1, which is the first well that we will produce at restricted production rates. Located in the Section 17, of 13:11 the well has been restricted to a 14/64 choke since the onset of this post frac flow back. The well was placed on production July 21 and has steadily increased its rate and pressure to the point that it was producing 8.9 million a day with 9,035 pounds flowing casing pressure on the same 14/64 choke.

We intend to produce this well on the restricted choke for the foreseeable future, with the intent to be able to compare decline characteristic to other wells in the area that have been produced on larger choke sizes. This comparison could help aid our production practices in the future, as well as possibly provide a new set of data with which to project EUR.

During the second quarter, we continue to see improved efficiency with both the drilling and completion of our Haynesville wells. Some of the techniques employed during the drilling operation were the use of rotary steerable drilling systems, shorter curves by using more aggressive bottom haul assemblies, which have decreased the footage necessary to drill the curve.

Automated high choke pressure systems, high pressure choke systems that provided less down time, due to excessive gas in the mud system. More aggressive PDC bids and bottom haul assemblies that have resulted in numerous days of greater than 1,000 foot drill, while in the lateral section, and the rotating of our casing to bottom, which has decreased the risk of not getting casing to bottom, as well as shorten the time it takes to land our casing.

All of these changes has helped drive down the number of days from spud-to-spud, which currently is averaging 45 days. Some of the completion changes that we have tested include longer frac stages with more per customers per stage that has decreased the number of stages pumped and therefore decreased the cost of the fracs.

We have also increased sand and water volumes per stage, used some limited percentages of Ottawa stand and advanced of the high strength profit and have increased our use of ceramic hydro problem. We are carefully studying the effects of these changes to hopefully design a completion technique that will optimize cost well at the same time optimizing well performance.

Switching to the discussion of the Eagle Ford Shale trend, our excellent results in the Hawkville Field continue to support the belief that this discrete geological area appears to be a highly commercial field. The company drove drilled six wells in the quarter and completed three of them at an average IP rate of 9.3 million per day.

Similar to the Haynesville production practices, these IP rates where all obtained by producing the wells at a maximum rate on a 24/64 choke with average flowing casing pressure of almost 4,200 pounds. Additionally, we completed the J.C. Martin well in mid-July at a rate of 8.8 million a day and 50 barrels of condensate on the 24/64 choke with 3,710 pounds for casing pressure.

This brings the total number of wells on production to eight of which seven have been on production for at least 30 days. The average rate of those wells based on a 621 Gascon estate ratio was 6 million a day and it was 6.9 million a day when calculated using an 18 to 1 gas to and condensate ratio and using the appropriate BTU adjustment.

Additionally, a few of the wells experienced some curtailment during the first 30 days, in which case the normalized 30 day average using conventional gas ratios against condensate ratios were 6.6 million per day and 7.6 million per day, when using the higher ratio assumption.

While there is not sufficient production history to utilize the time zero EUR forecasting method that we presented earlier on the Haynesville wells, we are very encouraged with performance of the wells to date and confirm the belief that the EUR range should be in the 4 to 7 Bcf range.

The economics of the fields have been greatly enhanced by the dramatic decrease in well cost. At the end of the second quarter, we had drilled six wells without intermediate casing, without drilling a pilot hole. Those wells have averaged reaching total measured depth of approximately 16,000 feet in 18 days from spud, which is a result in an average cost to rig release of $2.4 million.

Combine that with a significant reduction in service costs, specifically pumping services and the result is total well costs that are averaging slightly less than $5 million. Similar to the Haynesville, we have been varying certain aspects of our frac jobs, in order to optimize the cost versus benefit ratio.

The most significant change within a significant increase in the number of stages. The last two wells that we have fraced, we have pumped 18 stages. This has decreased the average stage link in these wells to approximately 245 feet with eight per clusters per stage that are approximately 30 feet apart. While it is too early to determine whether this project will be more effective, there does appear to be evidence of a flatter decline curve in early data, which could have significant impact on the EUR.

While we have focused the majority of our efforts to date in the area of the Hawkville field, we have been actively putting our geological experience to work in identifying areas and the trend that appeared to have rough quality, similar to what we have found at Hawkville.

These efforts have resulted in obtaining leases in several additional perspective areas in both the up-dip and mid-dip areas of the field. This leasing along with additional leases acquired in Hawkville has increased our net leasehold position to approximately 210,000 acres.

Lastly, regarding the Fayetteville Shale, we have intentionally decreased our operated focus in the Fayetteville Shale, in order to ensure that timing development of our leasehold and Hayneville and Eagle Ford. As recently as the middle of the fourth quarter of 2008, we were operating 11 horizontal rigs in the field.

But have now decreased that to two rigs. However, due to the increased level of activity and exceptional operational results of our non-operative partners, we have been able to achieve steady and impressive production growth in the field. At the beginning of the year, our net production in the field was approximately 71 million a day and by the end of the second quarter it had grown to just over 80 million a day, or approximately 13% growth.

While we are still very positive about the opportunities set in the Fayetteville, we will continue to direct the majority of our capital expenditures to the Haynesville and Eagle Ford over the next two years as we develop our term leasehold in each field.

With that I will turn the call back over to Floyd.

Floyd Wilson

Thanks, Dick, and that is a load of new data there. We have had a great quarter and great first half and feel really well prepared to sail through the rest of 2009. We have time for some questions now, if there are any?

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Jason Gammel.

Jason Gammel - Macquarie

Good morning guys and thank you for taking the call. First of all I wanted to ask Dick about spud-to-spud time that you are seeing in the Haynesville, you downed about 45 days now pretty impressive decrease, do you think that is about where it flattens out or is there still some scope for a decrease in that spud-to-spud time?

Dick Stoneburner

Actually, I had qualified that spud-to-rig release; there are still a few days from rig release to the next spud. But to answer your question, I think there is still continued room for improvement, all of the things I mentioned that we are experimenting with and utilizing to increase to RRP and basically get the wells, two casing early are still improving.

Jason Gammel - Macquarie

And maybe if I could just ask one more about, I am kind of stumbling around trying to find the (inaudible) I am not able to look at it yet, but another operator has indicated that they think first-year declines are now going to be about 85%, versus what they have previously thought to 81% in the Haynesville. Is the data that you're saying indicating that a bit steeper first-year decline were you saw something – something around 80%, 81% is what you are most likely to say?

Dick Stoneburner

We have been talking about 80% and 85% and we wouldn't disagree with the observation that many of the wells declined by 85% the first year.

Jason Gammel - Macquarie

Okay and then just maybe one more if I could. In the move in to Shelby and Nacogdoches, I know it is very early days, are you able to make any contrast in what you are seeing with the rock in those counties versus what you are seeing within the core area they have in Louisiana?

Floyd Wilson

I would like Dick to respond to that. I will say it is highly competitive process down there and of course we see some similarities in some of the very few data points that we have, would you add to that Dick.

Dick Stoneburner

I would kind of say that you would almost have to rewind to a year ago and when we talk about that area of the field, there is such a limited amount of data available to us, like Ford said it is very competitive and I don't know that I really wanted to get to a lot of the detail that we see, but we are encouraged. And we are attempting to expand our opportunities set down there, but beyond that I think I would hesitate to give much more detailed.

Jason Gammel - Macquarie

Okay. Fair enough. I appreciate the comments guys.

Operator

Your next question comes from the line of Michael Hall.

Michael Hall - Stifel Nicolaus

Hi thanks very much. Solid quarter, congrats. Just wondered if you could talk a little bit, we're seeing a lot of cost savings throughout the industry and just wonder if you could talk a little to the increases in quality as well, and obviously you have lot o efficiency improvements and how much of that is just tweaking the recipe as supposed to just our quality services, given the reduced activity levels out there?

Floyd Wilson

If you're speaking specifically about the Haynesville I will take it. We clearly are benefiting from the learning curve from the – that the service providers have experienced. Keep in mind that we started off with a pretty good recipe, if you will, that our tweaks have been rather small, rather large, which is – you know tells us we have started out on the right track.

I would say that there is still a lot of room there for things do continue to improve and of course those types of efficiencies that we are talking about aside from just cost reductions or lasting improvements in the these large-scale developments, the other – your costs are going to go back up, if commodity prices rise, but your efficiencies will stay with you.

Michael Hall - Stifel Nicolaus

Very good. Then thinking about your reserve outlook for the year, I mean are you expecting reserves to kind of continue to grow consistently with production and do you think reserves will exceed – reserve growth will exceed production growth, you see that (inaudible) expand this year, any commentary there?

Floyd Wilson

Certainly a wildcard, we have a goal of course increasing reserves along with production, we really need to wait till later in the year to comment on that.

Michael Hall - Stifel Nicolaus

Okay, fair enough. If I one – if I may one more, can you come at all on the exploratory counties and the Eagle Ford and kind of which direction you are heading, is up-dip north or northeast any commentary there or color?

Floyd Wilson

I know Dick would really like to talk about that, but I'm going to hold him back. It is highly competitive if we have – been reviewing some areas that are both for reef and back reef up dip if you will and we are very specifically targeting some areas that have a geologic story rather than just acreage. Beyond that it is so competitive down there right now that we are just not going to comment too much.

Michael Hall - Stifel Nicolaus

Okay, kind of figured, but it was worth a try. Thanks gentlemen.

Operator

Your next question comes from the line of Ben Dell.

Ben Dell - Bernstein

Hi guys. I guess my question was, if you look at your Haynesville Shale acreage that you have in the Eagle Ford Shale acreage and you look at the least than the number of wells you have to drill, if you take the current cost structure that you have on a per well basis, and you assume you wanted to hold all of the acreage, do you have a rough estimate for what the total capital spend would be over the next three years to achieve that?

Floyd Wilson

No I don't have that number at your fingertips. It is easier for me to respond in terms of a well and operated well count and we are staying well ahead of that curve in both the Eagle Ford and the Haynesville Shale. We of course have some leased capture issues in the Haynesville Shale by mid-to third quarter of 2007 or something that we are dealing with.

We don't have quite that pressure in the Eagle Ford Shale there is somewhat longer leases plus continued development drilling cost in most leases. I think the best way for me to state that is, that we are staying ahead of the curve that is required of us in terms of how many wells we need to drill to save the essential acreage in the field in the play, in both plays.

Ben Dell - Bernstein

Would it be fair to say then that your run rate for rig count and well count has to accelerate through the next two years to hold the acreage or do you believe it can be held flat?

Floyd Wilson

We are already projecting flat for 2010 in terms of capital spend perhaps with a few extra wells drilled because of cost savings. We certainly don't need to accelerate during the primary term of our leasehold in either the Haynesville or the Eagle Ford, we have that, we think wells hoped out.

Ben Dell - Bernstein

And maybe if I could just ask a separate question, can you give us some color on the average frac length of your say first five Haynesville wells versus the average frac length today?

Floyd Wilson

Track length?

Ben Dell - Bernstein

Yes.

Floyd Wilson

You're talking about wing length of a frac that is all conjecture, maybe I am misunderstanding the question.

Dick Stoneburner

You mean lateral length or stage length perhaps?

Ben Dell - Bernstein

The average half distance away from the well bore, what you believe that was in the original wells and what it is on your later wells?

Dick Stoneburner

That is not a measurable number, that is a theoretical number that is very difficult and they basically speak to the well spacing and that is something we are studying very, very aggressively, but to really pin point a frac length is really not a, you can – one thing you can do is look at micro seismic, but that doesn't necessarily show where a prompt fracture is, so it is really not an answerable question.

Ben Dell - Bernstein

Okay.

Floyd Wilson

Most have got a lot of variability in natural fracturing through these fields and that is a whole new variable in terms of the frac length itself.

Ben Dell - Bernstein

Sure. I guess I am just trying to understand, what your minimum down spacing would be based on the size of the fracs you are currently doing based on your current thinking?

Floyd Wilson

You know our current thinking is certainly going to evolve, we don't have any areas of the field that we have down spaced yet, our early work that we had done on the core, which we have reported in the past suggested that 80 acres was an appropriate number. We are hoping with more effective fracs and longer lateral that we can actually increase that spacing to more than 80 acres in other words to 100 or 120 or something acres per well, we just don't know that yet.

Ben Dell - Bernstein

Okay. Thank you.

Operator

Your next question comes from the line of Leo Mariani.

Leo Mariani - RBC

Hi thanks good morning again. I just wanted to clarify what you guys think your 2009 CapEx spending is going to be?

Floyd Wilson

We have a budget that is set at 1.3 billion at this time. It is about 300 million for infrastructure, about 1 billion for drilling in completion. About 800 of that is operated and about 200 of that is non-operated.

Leo Mariani - RBC

Okay, and I guess in addition is there any sort of ballpark spend you guys think you are going to have on acreage and can you tell us what you spent to date?

Floyd Wilson

Of course we don't budget at – I think we reported in the second quarter that we spent about 60 million or so on – go ahead Mark.

Mark Mize

That is correct. I think it was maybe somewhere around the $100 million number in the second quarter. That is year-to-date number by the way.

Floyd Wilson

First half, somewhere around the 100 million, we have a few commitments beyond there, but –

Leo Mariani - RBC

Okay. I guess just jumping over a – probably a different topic here, how many Haynesville rigs are you guys running right now on an operated basis and do you plan to increase that and do you have a year-end target for rigs out there?

Dick Stoneburner

Yes, we are operating 12 horizontal rigs and two what we call pre-drill or spudder rigs, we intend to escalate to escalate to horizontal count by approximately the fourth quarter call it October 1 to 16 horizontals. And we are going to face out the spudder rigs, we found that with the kind of the decrease in the spread on service cost, it is really – is beneficial as it was early on, so we will not run those into the fourth quarter, it will just be 16 horizontal rigs.

Leo Mariani - RBC

Okay. And I guess, the same question on the Eagle Ford; do you guys plan on adding rigs as we get later in the year?

Dick Stoneburner

No, we are pretty comfortable with the three rigs that we have right now, as Floyd alluded to, we are under no pressure from a lease stand point to accelerate that. I think the only acceleration maybe in the future is commodity pricing may allow us to spend more money down there.

Leo Mariani - RBC

Okay and can you just provide a little bit more color around that in terms of what your average lease term is down there, whether or not you have got extensions in any sort of color you can give on what you would need to hold a lot of those leases?

Dick Stoneburner

We have – I think in the general sense, we plan on staging up to six rigs beyond 2009. We don't have any lease capture issues that aren’t dealt with our current plan.

Mostly all of those rigs in South Texas have continuous development causes, which as you know are very beneficial to an operator and then many of the based leases of large leases.

So that you can – as long as you continue drilling at the primary turn you continue to hold those leases.

Leo Mariani - RBC

Okay and I guess last question here on the Eagle Ford, how is your infrastructure down there as you guys ramp up production you know into the end of the year and into 2010, is there any point you are starting to get concern that you are doing more processing or more takeaways?

Dick Stoneburner

Well we certainly are planning for a market increase down there. The early stage of this development has seen a few wells that were curtailed or shut in while we were laying pipe. We expect to kind of catch up with that by year end and be in really good shape in terms of infield takeaway capacity and of course we have already arranged for overall take away capacity. So, it is really looking good there and as you know we start planning for that sort of thing. About the time we start buying leases.

Leo Mariani - RBC

Okay, thanks, guys.

Operator

Your next question comes from the line of Chris Pikul.

Chris Pikul - Morgan Keegan

Floyd if you look into 2010 and see the need to fill the gap between cash flow and your projected $1.3 billion budget, can a kind of talk about when you see the company as sort of turning cash flow positive especially in light of your need to maybe accelerate drilling beyond 2010 to hold some of these Haynesville leases.

Floyd Wilson

First of we see no need to accelerate drilling past 2010, that will more a function of gas price in our outlook at that time. As Dick said with a sort of flat projection, from year-end ’09 forward we expect a whole lot of our leases. We don't make cash flow projections as you know, we certainly intend to – you know not spend cash flow forever.

Chris Pikul - Morgan Keegan

Okay. I must have misunderstood your comment earlier about holding leases. But, your bank line goes up as a result of significant Haynesville, Eagle Ford reserves; are you in a position where you are already looking to draw down on that in 2010 or is that something you see moderating just there for flexibility?

Dick Stoneburner

Well, we certainly would be utilizing our revolver during 2010, periodically, but you know it is – that is what it is there for. Keep in mind that we do have the intention and desire to divest the certain amount of our properties said here this year and that helps – if that happened that will certainly help our overall outlook in terms of liquidity.

Chris Pikul - Morgan Keegan

Right, and then in terms of total spending next year, can we expect similar infrastructure investment or is there lot of upfront cost, we should be considering.

Dick Stoneburner

It is similar on a projected basis that it is a bit less in 2009, but it is similar – there is a lot of upfront as you might guess, but as a result of our upfront investment, taking Haynesville as the great example, I think currently we are averaging 20 or 22 days or something from rig released for sale and we expect to compress that even – or we hope to compress that the future.

And that is an awesome place to be in and often times in a new development like that you might find yourself waiting months or even a year, you know for hook-up and we are just luckily or fortunately, we got way out ahead of that.

Chris Pikul - Morgan Keegan

Yes we are seeing an impact to that. Thanks for the color, I appreciate the time.

Operator

The next question comes from the line of Ron Mills.

Ron Mills - Johnson Rice & Company LLC

Good morning Floyd. Just on the Permian sale, I know it represents you know 31 million a day of production, is it on a percentage basis or is it a similar percentage of your reserves or on a reserve basis is it higher of your total reserves, I guess I'm just trying to get a sense as to what is left in the Permian after you have done some divestitures over the course of that year or two?

Floyd Wilson

We have I think it is a little under 200 billion. We have reported that in the future and they are of course they will be opening up in a couple of weeks here. And it is essentially our Permian – our subset that involves our Permian property.

Ron Mills - Johnson Rice & Company LLC

Is it your typical Permian production or is it 50 or 60% oil as well?

Floyd Wilson

It is around numbers of half crude and natural gas liquids and half natural gas.

Ron Mills - Johnson Rice & Company LLC

All right and then in terms of, maybe for Dick – you preferred J.C. Martin well where you actually had the 18 frac stages are you extending the lateral length in that play and what do you think is the numbers in characteristic in terms of lateral length? And then in terms of frac, (inaudible) you think you will also get down on the 200 feet or so per stage?

Dick Stoneburner

Ron, it is so early. Like I said in the script, I'm very encouraged by what we see early time, but it has only been two or three weeks since we have put that well of sales, so it is too early to call. We fraced a second well at the similar recipe and we will continue to watch, I mean it is like any play it is going to evolve, we have only got eight wells on production.

I think directionally, it would be the best answer that we could drill six maybe even 7000 per laterals. These wells are very easy to drill once you get them flat, we have had days where we have approached 1500 feet a day and we generally don’t see a lot of issues getting out to the 5000 foot range that we are currently getting to.

So, I would like to think that with more time and experience we can extent those lateral lengths and just drill less wells, which is the best answer, but it is still way too early to say. Stage [ph] length could go back to 400 feet I mean we are doing that in the Haynesville, we are increasing our stage length in the Haynesville. So we are trying different approaches in both fields and at some point we will have a more refined recipe, the good news is they are working quite well right now.

Floyd Wilson

But, I don't we had any trouble getting on the (inaudible) job.

Dick Stoneburner

Like a charm we didn't like 6 day. Three stages a day.

Ron Mills - Johnson Rice & Company LLC

Okay, good. So the 5000 foot is kind of what you have done in your most recent couple of well.

Dick Stoneburner

Yes, that is kind of where we are at, plus or minus on our wells on a go forward basis.

Ron Mills - Johnson Rice & Company LLC

And then lastly, just on the Haynesville, the geological mapping that you have done obviously should end up proving to be pretty beneficial are you also participating in any of the seismic suits, which can also be used to help enhance your internal geologic mapping?

Dick Stoneburner

Any seismic?

Ron Mills - Johnson Rice & Company LLC

In 3D, yes.

Dick Stoneburner

Oh, yes, we have got, while we have one proprietary suite that were the lead for the operator on the (inaudible) I think it is plus or minus 300 miles, we are involved in a couple of suites. That holds deal within the next 12 to 15 months; we will have 3D data on it.

What it provides us time will tell. It is not a terribly complex area from a faulting standpoint, but I am sure we will find faults that we don't see today. We would like to think we will see an AVO effect. We have modeled it. There is an indication that we can probably identify where the better higher gas saturated and higher property (inaudible) rock is that is preposition at this point, but that is what we are hopeful of getting out of it.

So it'll be very interesting to see what it delivers.

Ron Mills - Johnson Rice & Company LLC

Okay. Any changes in the terms of the timing that you have heard from any of the five companies in terms of the infrastructure expansion (inaudible) capacity in the Haynesville?

Floyd Wilson

You know, Steve is here who runs that part of our business, I think we are – our outlook is still that we are well covered in our cycles here as well. Our outlook is – they were well covered and there is a few new projects that we have a piece of that we don't really expect to be disadvantaged going forward, is that fair? In case you couldn't hear, we are looking forward to some new capacity in 2012 beyond what we have already contracted for, and we will certainly take our share of that or try to fulfill our needs from that. We are really in good shape and looking forward to some new capacity coming in for the entire area in about 2012 and beyond.

Ron Mills - Johnson Rice & Company LLC

All right. Thank you very much.

Operator

Your next question comes from the line of Adrel Askew [ph].

Adrel Askew - Hartford Investment Management

Yes, thanks. Can you talk about the cost simplifications of this profit change in the Haynesville and also I guess the latest wells that you drilled this Matthew 17 well what was the total cost on that well?

Floyd Wilson

On the property change, the economics of the part of the frac job that involved a profit have gotten quite similar between resin code and ceramics so that there are not real cost advantages to speak of anymore. So we are running, and Dick again correct me, but maybe a third of our wells going forward will be ceramic and two-thirds will be resin code. And over time we will have a really good comparison between our own wells and some of the wells that are in this information consortium that we can contrast and compare with.

Dick Stoneburner

That is accurate. Second part of your question, the Matthews?

Adrel Askew - Hartford Investment Management

Yes, the Matthews well, can you talk about some of the changes of the things that you did there, did you consider that to be the pretty much the suite, another suite spot of the play and what will the total well cost there?

Dick Stoneburner

It was consistent with the rest of our wells. I don't think we talk about individual well cost per se, but the actual production practice, we don't have a lot to compare to, but intuitively the 9,035 pounds that we see on this 14 choke with almost 9 million a day, I do think it is a better than average well, but we really don't have the comparative data to support that, but what I am encouraged and very anxious to see is how that well holds up, you know over the next four, five, six months and be able to make a comparison.

And that is the whole purpose behind the program. We have got three other wells identified where we have good offset analogs that were produced under the – call it the old school way, so we will compare that over the next four, five, six months to see how they compare, but it is just very encouraging right now. It isn't every good area it is not surprising as a good well, but I think it is probably an exceptionally well.

Adrel Askew - Hartford Investment Management

Okay, great. On your EUR assumption of 7.5 Bcf what years of production are you assuming then also what about terminal decline on that?

Dick Stoneburner

30 years, 6%.

Adrel Askew - Hartford Investment Management

That is helpful. And then one more if I could, so for – what is going to be your approach as far as your hedging program in 2010, are you guys still learning on hedges, I know you said you learn on some for 2011, what are you doing so far as 2010 as well?

Dick Stoneburner

As you might guess, production growth that we have experienced leaves us a little bit short of our goal of 70%, so that we are adding hedges. We have actually added a few hedges for 2009, fourth quarter. We are layering in a few for 2010 and certainly have been very active during the second quarter in putting in hedges for 2011. Our overall goal is still to try to attain about that 70% level and as you know even though the prompt month is low that the curve is still pretty attractive for this edge business.

Adrel Askew - Hartford Investment Management

What price level are you guys seeing here recently? Where are you layering [ph] them in now, on gas?

Floyd Wilson

There’s an update I think, on our Web site. But 2011, I think our collars [ph] are around five – 550 by '10.

Adrel Askew - Hartford Investment Management

Okay.

Floyd Wilson

I think for 2010, what, about five by eight?

Mark Mize

About six by nine.

Floyd Wilson

Six by nine. So it’s really – again, our hedges this year are sort of like eight by 12. And we put those on a year and a half ago. We’re kind of following that practice of making sure we’re looking at the hedge market. As prior periods roll off, we’re looking to expand those hedge positions.

Adrel Askew - Hartford Investment Management

Yes. Is that something we can consistently expect? You guys talk about trying to be 70% hedged. Is that something we can consistently expect going forward, I guess?

Floyd Wilson

That’s certainly our goal.

Adrel Askew - Hartford Investment Management

Yes.

Floyd Wilson

We do try to be a little opportunistic in placing the hedges. But we still try to obtain our goal.

Adrel Askew - Hartford Investment Management

Yes. I got you. Okay. Great quarter, guys. Thanks.

Operator

Next question comes from Adam Leight.

Adam Leight - RBC

Good morning. I just have a quick follow up on the capital program for 2010. I know the budget hasn’t been set, but are you looking at a shift in the drilling-infrastructure mix? Is there more drilling in there to help the production ramp up?

Floyd Wilson

Actually, Adam, we have announced a 2010 budget of $1.3 billion, about the same spin level as 2009. It involves a slightly less infrastructure spend; a bit less in the Fayetteville, a bit more in the Eagle Ford, and sort of flattish in the Haynesville. And you can see those charts on our current – on the Web site.

Adam Leight - RBC

Okay.

Floyd Wilson

We actually projected production for 2010 –

Adam Leight - RBC

I got the production and I got the total. I guess I missed the breakdown. Sorry. And then –

Mark Mize

Now Adam, we are going to increase ever so slightly, our North Louisiana conventional, which we have not done in ’09. So that’s another point that we’ll establish in 2010.

Adam Leight - RBC

Can you give a give a sense of what the overall decline curve might be looking like after 2010?

Floyd Wilson

Adam, we don’t really –

Adam Leight - RBC

Quite right.

Floyd Wilson

– put that out there. It’d be typical for our company, of our reserve life and reserve level, I would say.

Adam Leight - RBC

Okay. Last question on working capital. Is that going to continue to be a use of cash for you?

Mark Mize

(inaudible) continue to be a use – a use of cash – I mean, I guess the simple answer would be, yes. If you just look at the current expenditures of the company, we are continuing to up spend [ph] cash flow this year. And we would anticipate doing so in 2010 as well. Does that address your question?

Adam Leight - RBC

No. On the working capital side; not CapEx in total; the working capital.

Mark Mize

I tend to take more of a corporate look at cash flow. So off the top of my head I don’t have an answer for you, specifically just on working capital. But I would tend to believe that it’s a – not a negative number.

Adam Leight - RBC

Okay. Thank you.

Operator

Your next question comes from the line of Subash Chandra.

Subash Chandra - Jefferies

Yes. Good morning. I guess the question is for Dick. I think, Dick, (inaudible) I saw in the presentation, you referred to permeability in Eagle Ford sort of over a thousand Anadar season [ph]. And I was curious if you’re seeing that pretty much everywhere or if you’re seeing some variety to the perm? And then secondly, is there a tipping point for too much liquids in the stream?

Dick Stoneburner

Regarding perm, Subash, we have two core available to us at this point. The third one’s still in analysis. I think the 1.1 was the higher of the two. But the other one was not too far behind it. Though it was probably – I can’t, off the top of my head. It wasn’t higher than. It wasn’t quite as high as, but it was close.

In terms of liquids, I don’t think so, Subash. For one, it’s a great revenue add. But you’re comment is probably more addressed to performance. And you know, in this type of rock with nano-perm and in a highly fractured network that we’ve induced, we don’t think – and peers that I’ve spoken to, whether it be Marcellus or other areas of the Eagle Ford, I don’t think anybody is seeing, number one, any detrimental effects to date, or expect any.

It’s just not the same type of situation in a conventional high-perm reservoir where you have a retrograde condensate reservoir. Any liquids that drop are nominal. And your fracture network has sufficient perm to deliver those liquids and gas without a change. That’s our opinion.

Subash Chandra - Jefferies

Got you. Okay. And one final one here, any outlook on what the banks will do in Q3 as for their price decks [ph]?

Mark Mize

Pricing has come off from the last re-determination that we had. But we are adding reserves. And we are probably going to have some of the banks veterans step up and then maybe new ones come in. So we are looking to take a part in (inaudible).

Floyd Wilson

Subash, I think the – in a general sense, the last pricing re-determination was grouped around a $4.50 gas price. It went up $0.50 a year for three years and this next time, we expect to be around $4. It goes up about $0.50 a year for three years.

Subash Chandra - Jefferies

Got you. Terrific. Okay. Thanks, guys.

Operator

The last question is from the line of Beau Batner [ph].

Beau Batner

Good morning. I just wanted to revisit the ’09 capital budget. See if you can help me maybe back into or get to the $1.3 billion number. I looked at Q and what you’ve spent to date back up the acquisitions of $100 million, give or take. Looks like you’ve spent about $325 million a quarter just on E&D. Going forward, to get to the $1.3 billion, it looks like you’ll have to cut spending to about $175 million on average for the third and fourth quarter to stay within that budget.

Non-op activity in Haynesville, or that’s Fayetteville’s gone up. You’re adding rigs in Haynesville and the Eagle Ford. I’m just curious how the budget is maintained at that $1.3 billion level?

Mark Mize

I’m going to give you an answer and you can let me know if I nail it for you. If you were to look at our cash flow statement that we present in our Q for the six months ended, you’ll see that we had our own gas expenditures of $750, or just under. And then we had other operating property and equipment expenditures of about $145. If you add those together, you get just under $900 million.

But then, it’s not publicly disclosed. But we had mentioned earlier that we had somewhere in the $100 million range of unbudgeted acres that were acquired. That number, fine tuned for the six months, is about $116 to $118. If you back that out, and if you also take into consideration accruals, which you would need to remove from your cash flow number that gets you down to right around the $650 to $670 number. Which times two, is just over $1.3 billion. So that reconciles it for you.

Beau Batner

Yes. I know. I get to the $650 in terms of E&D spending in the first half. You add in the $300 million of the mid-stream spending. If I understand correctly, the $1.3 billion includes both E&D and mid-stream spending, $1 billion for E&D, $300 million for mid-stream.

So if I take the $1.3 billion less the $950 spent to date, that’s $350 remaining for the second half of the year. Are we talking the same numbers?

Mark Mize

I believe we are. But again, I’m working straight off the cash flow statement and just trying to sink up [ph] or reconcile back from the cash flow to a mid-year number that would be pretty much dead on 50% of our ’09 capital budget.

Beau Batner

Is the $750 spent on – regardless of mid-stream, that’s $750 – am working from the cash flow statement, as well? $750 less roughly the $100, plus or minus, on acreage, gets you to $650 just for the E&D portion of your spend through the first half. If I take the $1 billion, which you referenced as your E&D budget, less the $650 that leaves $350 remaining. And that works out to about $175 a quarter, on average. Down from the $325.

Mark Mize

Let me give this one more shot and if we need to we could take it offline. But the detail would be drilling right around $537, you have (inaudible) services coming in around $145, there’s an accrual adjustment right around $100 million, then you have the unbudgeted acquisitions right around $115. So if you take all of that into consideration, you ought to be able to tie back into our $1.3 billion budget. But if you’d like to go into more detail or granularity, we’d certainly take the call right after this one.

Beau Batner

Okay. I’ll do that. Thanks.

Mark Mize

Thank you.

Floyd Wilson

Well then, thanks, everyone, for dialing in today. We’re really proud of the quarter that we posted and look forward to the rest of 2009. And if we didn’t cover something, feel free to give us a ring after this call. Thank you.

Operator

This concludes today’s conference call. You may now disconnect.

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: transcripts@seekingalpha.com. Thank you!

Source: Petrohawk Energy Corporation Q2 2009 Earnings Call Transcript
This Transcript
All Transcripts