EQT Corporation (EQT) Q1 2012 Earnings Report, Transcript and Summary

Good morning and welcome to the EQT Corporation First Quarter 2012 Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions) Please note this event is being recorded. Now, I'd like to turn the conference over to Mr. Patrick Kane. Please go ahead. Patrick Kane – Chief Investor Relations Officer: Thanks, (Emily). Good morning, everyone and thank you for participating in EQT Corporation's first quarter 2012 earnings conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream, Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production. In just a moment, Phil will summarize our operational and financial results for the first quarter 2012, which were released this morning. Then Dave will provide an update on our strategic operational matters. Following Dave's remarks, Dave, Phil, Randy, and Steve will be available to answer your questions. I'd like to point out that today on our website we provided additional details on our cost per well and EUR per well at different well lengths. Historically, we have provided these estimates assuming a 5300-foot lateral, which was our projected average. As you will see, the EUR per foot of lateral is unchanged and the cost per well is lower. This call will be replayed for a 7-day period beginning at approximately 1.30 pm Eastern Time today. The phone number for the replay is 412-317-0088. The confirmation code is 10006583. The call will also be available for seven days on our website. But first, I'd like to remind you that today's call may contain forward-looking statements related to future events and expectations. You can find factors that could cause the company's results to differ materially from these forward-looking statements listed in today's press release under risk factors in the company's Form 10-K for the year ended December 31, 2011, which was filed with the SEC and updated by any subsequent Form 10-Qs, which are also filed with the SEC and available on our website. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure. I'd now like to turn the call over to Phil Conti. Phil Conti – Senior Vice President and Chief Financial Officer: Thanks Pat and good morning everyone. As you read in the press release this morning, EQT announced first quarter 2012 earnings of $0.48 per diluted share, a 42% decrease from EPS in the first quarter 2011. The first quarter of 2012 included $6.2 million of expense associated with the retroactive portion of newly enacted Pennsylvania legislation imposing an impact fee on all wells drilled in the state including those wells drilled prior to 2012. In addition, there were two items that cumulatively added $36 million to our pre-tax income in the first of 2011 which distort the year-over-year comparisons. Adjusting for those three items, EPS was $0.50 this year compared to $0.60 in the first quarter last year or a 24% decrease. The decrease in EPS comes as a result of lower natural gas prices on our un-hedged production, lower operating income at Equitable Gas as a result of unusually warm weather, and higher depletion rates at production. All of which more than offset another solid operational quarter including record produced natural gas sales and another record in gathering volumes. Operating cash flow which adjusts for those 2011 non-cash items as well as the non-cash impact of higher depletion rates decreased by 9% to $227 million for the quarter. With that, I will go into a little more detail by business segments starting with EQT production, which continues to generate impressive growth in sales of produced natural gas. The growth rate was 26% in the recently completed quarter over the first quarter of 2011. That growth was primarily organic and was driven by sales from our Marcellus shale play, which contributed nearly 50% of the volumes in the quarter. As I mentioned, gas prices were lower in the quarter. The realized price at EQT production was $3.59 compared to $3.97 last year. At the corporate level, EQT received $4.84 per Mcf equivalent or 11% less than last year. Produced liquids excluding ethane accounted for 6% of the volumes and 34% of the un-hedged revenues in the quarter. Total operating expense of EQT production was higher quarter-over-quarter as a result of higher DD&A, production taxes, and SG&A. The increase in the depletion rate was primarily due to an increase in cost to drill and complete wells, the removal of some proved reserves due to lower natural gas prices at year end, and the suspension of drilling activity in the Huron play. As alluded to earlier, in February 2012, the Commonwealth of Pennsylvania passed a natural gas impact fee. The legislation, which covers a significant portion of EQT’s Marcellus shale acreage, imposes an manual fee for a period of 15 years on each well of drilled. The impact fee adjust yearly based on three factors, age of the well, changes in the consumer price index, and the average monthly NYMEX natural gas price. Production taxes increased primarily due to the $8.2 million accrual in the first quarter of 2012 for this impact fee. Again, $6.2 million of that represents the retroactive portion of the fee for pre-2012 Marcellus wells. Moving on to Midstream business, operating income here was up 10% versus last year excluding the impacts from the sale of the Langley processing complex and the Big Sandy Pipeline, and a reduction of non-income tax accruals in 2011. This is consistent with the growth of gathered volumes and increased capacity based transmission charges. Gathering net revenues increased by $10.3 million as gathering volumes increased by 21% while the average gathering rate declined by 4% driven by the Marcellus mix. Transmission net revenues decreased by 13% to just under $23 million, resulting from the loss of revenues associated with the Big Sandy Pipeline, which we sold in the second quarter of 2011. Adjusting for the Big Sandy revenues, transmission net revenues increased by 24%. Storage marketing and other net operating income was down about $6 million in the first quarter. These results included $5.4 million in unrealized losses related to our storage inventory and a steeper slope in the front end of the near term natural gas curve. Because we have financial hedges associated with those inventories, we expect to have unrealized gains that will offset these unrealized losses over time. Given current market conditions, we estimate that full year 2012 net revenues in storage marketing and other will be approximately $50 million to $60 million. Net operating expenses at Midstream were slightly higher quarter-over-quarter, excluding the impact of the previously mentioned non-income tax adjustments. For unit gathering and compression expense, again, excluding the non-income tax adjustments was down 7% to $0.28 per Mcf equivalent as a result of higher throughput while maintaining our cost structure. And then finally, on the Midstream on February 13, 2012, EQT Midstream Partners' limited partnership filed a registration statement with the U.S. Securities and Exchange Commission as we move forward on forming an MLP. Moving on to distribution, operating income, distribution was down 31% versus the first quarter last year. According to the National Oceanic and Atmospheric Administration or NOAA, the first quarter of 2012 was the warmest first quarter period on record in the service territory for Equitable Gas, 24% warmer than last year when measured by heating degree days. As a result, total net operating revenues for the first quarter 2012 were 19% lower, while operating expenses were down slightly excluding the prior year tax adjustments. Basically for each 100 heating degree day change in weather going to winter at Equitable Gas, our distribution margins change by about $2 million. So, the warmer weather in the quarter negatively impacted our EPS by about $0.05 per share versus normal weather and about $0.06 per share versus last year. Moving on to 2012 guidance, today, we reiterated our production sales forecast for full year 2012 of between 250 and 255 Bcf equivalent or 30% higher than last year. Our forecasts are intended to represent our realistic projection factoring in some negative impacts from inevitable unplanned delays or disruptions such as delays in Midstream projects, permit delays, weather impacts etcetera. As a result of the lower forecast of natural gas prices for our un-hedged volumes, we are decreasing our operating cash flow estimate for 2012 to approximately $800 million. At the same time, as a result of our lower well cost estimates, we are also lowering our 2012 CapEx estimates by $100 million to $1.365 billion. We exited the quarter with $745 million in cash on the balance sheet, no short-term debt including no cash frauds under our $1.5 billion credit facility. And so we remain in a great position as far as liquidity growth for 2012. And with that, I'll turn the call over to Dave Porges. David Porges – President and Chief Executive Officer: Thank you, Phil. As we have previously communicated, our objective of maximizing shareholder value is unchanged by changes in the environment in which we operate. The strategy accomplishing this, the monetization of our asset base and prudent pursuit of investment opportunities while living within our means is also unchanged. Our tactics, however, can and must change when circumstances warrant. In an environment in which natural gas prices are down sharply, we have already made tough decision, but you have January suspension of Huron drilling cutting CapEx by about $130 million. We are focusing our drilling on our highest return opportunities with nearly 75% of our 2012 Marcellus wells being drilled in either our highest EUR areas or in the more liquids-rich portion of our West Virginia acreage. With the liquids uplift, the returns of the West Virginia wells are similar to more prolific dry gas wells in Pennsylvania. There is always a lag between making such decisions and having those changes show up with a cash register, but we are getting some immediate benefits from reducing our service cost as gas prices are declining. The cost of a 5300-foot well is down to $6.1 million from $6.7 million last year mainly due to those reductions. This will impact our 2012 CapEx, but will now show up in our depletion rate until next year just as last year's increases hit this year's depletion. Our online after-tax IRR estimate is now 29% at the current NYMEX five-year strip of 366 per MMBtu and 25% at a flat $3 NYMEX. Therefore, it is clear to us that investments in our Marcellus play remain attractive even at current prices. So, they are obviously not as attractive as they would be in higher prices. We believe that prices will begin moving up once the current storage balance is worked off, however, (the long) that takes, but are structuring our business, so that they can thrive in an environment, which prices never get above, where say the back end of the curve currently sits. Practically, this means that we will continue to prioritize our spending rigorously and focus on improvements in cost structure whether they come from different ways of doing things or reduction at service costs. So, this heightened focus has already resulted in some reductions in activity level, notably the Huron decision. I do want to reiterate what Phil mentioned about the volume guides for the year that is the fact that our growth versus same quarter last year is below our annual guidance, is not a result of changes in activities rather it's just the nature of the business given multi-well pads, large compressor stations, etcetera. Note, this is little lumpy. We also note that the three higher sequential growth rates in EQT's history in the fourth quarter of 2010 and the first two quarters of 2011. So, the current comparisons are a little tougher than they will be later in the year. As for cash flow, we are aware that projections are lower than they were a few months ago due largely to decline in natural gas prices, but the reduction in well cost keeps our CapEx forecast in line with this lower cash flow even at a constant activity level. We will, of course, continually monitor market conditions and adapt our tactics accordingly. In 2012, we are investing our operating cash flow plus also utilizing some of our other available capital. This other capital includes cash from our investment grade debt issuance completed in late 2011 and further monetizing Midstream assets by forming in MLP. As Phil mentioned on February 13, 2012, we filed the initial S1 for the MLP, but we recognize that this nearly starts the review process with the SEC. To remind you, the advantages of EQT shareholder – to EQT shareholders of forming an MLP includes, maintaining operational control of where, when, and to what specs gathering is built, access to an ongoing source of low cost capital, and participation in any MLP distribution growth. Of course, a publicly traded currency would also provide a market view of the value of the MLP's assets. Moving on to some other operational matters, as we told on the last call, Mark West is building a processing plant to serve our West Virginia wells. This plant was originally scheduled to be up and running by mid-year. However, due to a number of delays that they experienced in permitting and construction, the project is now scheduled to be complete in the first quarter. We are looking into work arounds that would improve on this, but believe that we will meet our production sales volume targets even with the current schedule. The real impact of this is not on the overall volumes, but rather that additional margins from the revenue uplift expected from liquids extraction FF plant will obviously being delayed somewhat. We are also working to a short adequate processing and transportation capacity to support our Marcellus growth beyond this year. We were an anchor tenant taking 150,000 dekatherms per day on Spectra Energy's Texas Eastern Pipeline expansion to Eastern Pennsylvania and Mid-Atlantic markets, plus 150,000 dekatherms per day of backhaul runs. The expansion is expected to be complete by the end of 2014. And we are in the process of securing additional processing capacity to enable further growth from our wet Marcellus acreage. In summary, EQT is committed to increasing the value of our vast resource via accelerating the monetization of our reserves and other opportunities. We continue to be focused on earning the highest possible returns from our investments and they are doing what we should to increase the value of your shares. We will say disciplined and live within our means investing our available cash from operations and from future monetizations as appropriate. We look forward to continuing to execute on our commitment to our shareholders and appreciate we’ll continue to. Patrick Kane – Chief Investor Relations Officer: Thank you, Dave. That concludes the comments portion of the call. (Emily), can we please now open the call for questions?

We will now begin the question-and-answer session. (Operator Instructions) And our first question will come from Neal Dingmann of SunTrust. Please go ahead. Neal Dingmann – SunTrust: Good morning guys. First, guys can you address maybe just a different source that you are seeing going forward? And then secondly as you sign – you talked about the MarkWest deal that likely signed up, how do you perceive sort of the infrastructure costs going forward if that deal was successfully completed?

So, we talk about ones, changes going forward, you are talking about on the infrastructure side?

Correct.

Randy, you want to comment on where you see infrastructure heading?

Well, with respect to the pricing, we haven’t seen a great deal of softening in the market from that standpoint, but in terms of the projects, EQT is working towards, we continue to be on time, on budget with our Sunrise expansion and in building up the infrastructure that connect to the plant. And as Dave alluded to we are looking in the interim to other options as well to move, to get our gas process.

We are obviously going to see average gathering rates decline even in the constant cost environment just as the mix continues to move towards the Marcellus, but we've mentioned in the past that the unit rates for Marcellus are roughly half that for Huron. So, as the mix keeps moving we will continue to see average declines even without a – because of mix change along. Neal Dingmann – SunTrust: Okay. And then just kind of going forward one last question just on the improved sort of techniques you are continuing to see, as far as what are you seeing that as far as opportunities why, just on a percentage, does that continue to expand and maybe cost that you see on that going forward. Are you able to as you continue to do more of these new processes, bring down the cost a bit on that completion?

Yeah, I think you’re talking about production. So, I will turn that over to Steve.

I assume you are speaking about completion techniques in particular? Neal Dingmann – SunTrust: Yeah, exactly, Steve.

Yeah. Well, we continue to really feel good about the results we are seeing with the new frac techniques specifically in the more brittle areas like we talked about. I think roughly 44% of our program this year we expect to use the new technique. And I think that benefits pretty well from the reduced service costs we are seeing. So, that’s been a big benefit as well that the cost for that new technique could come down along with the overall costs. Neal Dingmann – SunTrust: And then when your peers talked about just the tighter denser space, I mean, is that something Steve that also that you are looking into and do you assume, it look like that they talked about increase rates based on that, is that something that you’re looking at doing as well?

Well, I guess I would say we pioneered that.

Yeah, that’s what we are talking about. Yeah, that's what we are talking about, year and a half. Neal Dingmann – SunTrust: I guess, what I'm asked to Steve is as you continue to sort of on these specs do that, is that going to be basically majority, I mean right now it's still I don’t know what percent of your total program that is. I am just wondering if that will become sort of more mainstream here in the next letter part of this year for you?

Well, I think we still believe that it’s going to be location specific based on the brittleness of the rock. And our current estimate is that for 2012, 44% of our 132 wells will use that technique. Neal Dingmann – SunTrust: Well, okay.

In some of the cases, in certain pricing environment, it doesn't make sense and other pricing environment it does make more sense. So, depending on where natural gas prices go, there is kind of a gray area either somewhere it just seems that it basically always make sense. Others were basically seems that it never make sense so, on some place where it's little bit more sensitive to current economics. So, you can see that percentage moving up of that. Though, I would say and I think I look at the things that folks are doing. They keep working on ways to come up with the optical completion technique for each of those – for each of the areas on which we are working, whether it's the tighter spacing, which again we've been talking about for a – that's what we are talking about now, we talk about (specs) that's what we've been talking about for the last year and a half or thereabout or other techniques. Neal Dingmann – SunTrust: No, it still sounds like that combined with your long laterals you are really seeing some of the best results out there. Thank you.

But we'll keep working on, ever working on trying to get better and better. Neal Dingmann – SunTrust: Perfect, thank you.

Our next question comes from Scott Hanold of RBC Capital Markets. Please go ahead. Scott Hanold – RBC Capital Markets: Yeah, thanks. Good morning. A question for you, on your drilling program in the Marcellus obviously the gas price where they are, I guess you made the case that your economics are still good. And so, I guess that implies at this point in time, you are not going to make a change to your overall development program. But can you talk to the extent where you're shifting or you have the capability of shifting activity more to liquids from the drier gas parts of the plane. How much of that is actually going on at this point in time?

What we are shifting to the extent that we can obviously we only get the uplift and this is true for everybody goes not just does. We only get the uplift when you're actually able to extract enough of the liquids. We get a certain amount of the uplift just from the so called JT skids for you. But the mainly design just give you a pipeline quality gas of its, I guess the tastes where that can put you over into that making it more economic that I'm more prolific dry gas well. But what we're really focusing on more is the ability to link the development program with the processing capability. So, we're moving in that direction as much as we – as much as we can, but we are marrying the production activities with the Midstream activities. Scott Hanold – RBC Capital Markets: Sort of the delay in the MarkWest plant kind of I guess to a certain extent limit your ability to really focus a little bit more efforts in those areas.

Not right now because realistically a well that we spend right now, it does affect cash flows in 2012, right I don't want, we mentioned that in the prepared remarks and that's true. But those are on wells that hit over to the spot. For the decisions that we are making now to spot wells, the presumption is that we have a reason to believe those – that plan will be upon running and preferably some of the increased capacity that we made reference to would be ready as well because there is a lag between the decision to spot now comes online. So, now I wouldn't say that it's – that client doesn't impact the decisions that we're making on where the drill right now that delay there impacts really third quarter cash flows. Scott Hanold – RBC Capital Markets: Okay. And then maybe kind of referring to, may be the early part of the question I had so, if you're looking to the back half of '12 and the early '13, I'm not sure what you are assuming for gas prices. But are you making focused effort with MarkWest expect to be online in 2013 that you are going to drill in the higher liquids areas and can you be pretty fluid with that program if need be?

Yeah, but we work with any number of process, we just want to get our – the liquid extract from the gas and we get the revenue uplift from the propane and butane. Scott Hanold – RBC Capital Markets: Okay, how much of it?

Just one company, I mean, we talked about one company, that's one plant in North and West Virginia, but more broadly yes, we are as we look ahead, we are looking at making sure that we can as we said that we can continue to focus on both the areas that are more liquid rich amongst our acreage as well as the once that are more prolific, which really needs the dry gas so that are – that have the best economic. Scott Hanold – RBC Capital Markets: Yeah, if memory serves me that plant specifically with MarkWest that we are referring to is a $100 million a day.

Our capacity on that would have been is actually is $120 million a day. Scott Hanold – RBC Capital Markets: Is a $120 million a day? Okay. And then how much of an impact will that shift have or let me ask you the question this way when that plant comes online, how much of an annualized basis improvement would you get in pricing?

We have to be able to do the answer for that, probably the best opportunity.

Part of the Mcf basis, the liquids uplift gives us about $2.50 increase. Scott Hanold – RBC Capital Markets: At today's price?

At today's prices. Scott Hanold – RBC Capital Markets: Okay, alright. And that's $2.50 per...

Per Mcf. Scott Hanold – RBC Capital Markets: Per Mcf – on an Mcf basis, okay. One last quick question if I could you, Phil, I think you mentioned what your cash balance at the end of the year, I apologize I missed that, could you give us?

At the end of the first quarter by the way, I'm sorry, $7.45 was at the end of the first quarter. Scott Hanold – RBC Capital Markets: Yeah, okay, $7.45, thanks guys.

Our next question comes from Anne Cameron of BNP Paribas. Please go ahead. Anne Cameron – BNP Paribas: Hi, good morning. Not to be the dead horse on the West Virginia wet gas issue, but what is your current West Virginia wet gas production from the Marcellus on an Mcfe basis?

Yeah, we don't provide the breakout on Marcellus by state. Anne Cameron – BNP Paribas: Okay. So, I guess my – what I am driving at is when the MarkWest plant does come online is a 100 net enough to handle all of our wet gas production and how much more processing do you need?

Well, as we keep growing, we'll need more and more and that's we and we are currently working on and you are well into development what those alternatives are to keep processing more than the 120. Anne Cameron – BNP Paribas: Okay. And do you have capacity in the second mobile plant?

Maybe you talk about it…

Yeah, I mean, maybe we are – we have a firm right to a $120 million a day of that plant and MarkWest is putting in a larger plant and we are in discussions with them and others about additional. I would reference on capacity on the plate as well though that as we said before we've been proactive with adding a $100 million a day of capacity. We'll have a total of $100 million out of our Dodgeridge County and at the year end at our other wet area and that's another $100 million a day and with our Sunrise project, we've adequate residue gas to move that gas to market. So, we had been proactive in doing that and when the plant comes on, we're going to be prepared to move the product going forward. So, as they believe we're working toward getting additional processing capacity at this time.

We are not concerned about that overtime. The issue is when plants coming, it can move things by a quarter here and there, that's the issue, it's the near-term cash flow forecast, not the longer term strategy that gets impacted. Anne Cameron – BNP Paribas: Okay, thanks. And that $2.50 uplift, does that correspond to 1.8 gallons per Mcf excluding in the ethane?

Yes. Anne Cameron – BNP Paribas: Is that about right?

Yeah. Anne Cameron – BNP Paribas: And the $2.50 net of processing fees or is it growth of processing fees?

It was net. Anne Cameron – BNP Paribas: Okay, got it, thanks. And then in terms of the ethane, can you mix ethane indefinitely from what you can see right now into the gas stream.

Well, Anne, this is Randy. From what we can see right now, we have the adequate mix to mixed the dry to meet our pipeline specs and so as we said previously we'll make the decision whether it take the ethane based on economic conditions not on pipeline quality issue. Anne Cameron – BNP Paribas: What kind of infrastructure would be involved in moving that ethane either to the enterprise line or to the Mariner East project, if you did the side to extract it?

Well, our commercial arrangement at MarkWest provides the option that they would extract the ethane and move it.

Yeah so really the fact what it means it would take from that plant and would really just I think shift the whole thing up to their one of the fractionation facilities. So really that infrastructure already exists. It just a question on making the determination that it's economical to extract the ethane. Anne Cameron – BNP Paribas: Okay, got it. And then just a totally separate question, which you may or may not be able to answer given that your docs are still sitting with the SEC. The strategy for the MLP like really is the gain plant to gross third-party volumes with that business or is it really mostly just to process Equity Gas and like how….

What our General Counsel is looking at is shaking our hands. Anne Cameron – BNP Paribas: Oh, (indiscernible) okay.

We don't want to say anything that would make you more likely to buy the unit. So… Anne Cameron – BNP Paribas: Okay, okay, I'll backup. Sorry guys. Alright, thank you. That's it from me.

The next question comes from Michael Hall of Robert W. Baird. Please go ahead. Michael Hall – Robert W. Baird: Most of my questions have been answered. I guess couple of remaining one from me. May I talk about Northeast strategy that changing despite current environment, which make sense. But are there any other tactics that you are kind of reviewing currently that we haven't really talked about outside of just drilling additional liquid rich wells. Any other sorts of cost saving initiatives or things along those lines that are currently under consideration?

Yeah. We certainly continue to look at ways to improve cost structure and of course before I alluded to production, but the same thing is to a midstream continuing to improve cost structure. I am not sure I feel comfortable getting into the things that are simply in the development stage because we often look at different alternatives and yet test them out, you see what works and doesn’t. Michael Hall – Robert W. Baird: Got it. And I guess the other one is, have you reviewed or do you continue to review your legacy assets for any sort of Utica exposure I know in the past expense likely to just be in a dry windows. Is there any indication as we can better understand the windows potentially some wet gas and that as well or is there no real change there? Thanks.

Not really, I mean maybe there is, but really hadn’t been much change, but we haven't quietly spent too much on focusing on that. The large part of those, which is also deeper in Pennsylvania than it is in Ohio. So, our approach on the Utica is still pretty much what it was for our Pennsylvania acreage, which is – there is going to come a time where it make sense to drill down basically from the same pads that were using for the Marcellus. Because that will obviously involve an improved cost structure to be able to use all the same pads and well roads and compressor stations, etcetera. So, that will be settled – when we get to that point time that will show cost structure improvements too. Michael Hall – Robert W. Baird: Okay. That’s all I have. Thank you very much.

Our next question comes from Ray Deacon of Brean Murray. Please go ahead.

Ray, you there?

Mr. Deacon, your line is live. We'll move on to our next question. (Operator Instructions) At the time, we'll take a question from Craig Shere, Tuohy Brothers. Please go ahead. Craig Shere – Tuohy Brothers: Hi guys. Couple of follow ups on the frac geometry from Neal's question. First if I remember correctly when you'll first announce that it was said that I might add maybe a million dollar per well and cost, but you are obviously noting that services cost are lower currently so, that's really helping a lot. First part, do you have an updated figure for how much more cost per well to imply the new geometry and to the extent, Dave, we commented some of the new geometry was economic in some cases of less optimal brittleness based entirely on commodity prices. So, when you think about issues of hedging and when you think about commodity prices at their extremes. How does that kind of play into any expansion of this program?

On the first part, cost for the new frac – the additional cost per well is about $1.2 million for the 5,300 feet and that's down from $1.4 million previously.

On the price side I just generally speaking say that it the areas where it's kind of a gray area whether it makes sense or not. They tend to look better when prices go up. So, yeah, I mean, if you look at this is – if you want to look at any company as say one thing that would have been if there is a more than you say it's almost if there is the call options embedded price – long call options on gas price. We cannot to really factor that into much in the hedging because that's, I mean such a long – there is a longer term play. But you're right it does – it does suggest if prices are higher that you had more exposure. So, you may that is true, but I don’t know I said we formally corporate that where when we are looking at our hedging strategy. For the most part, the hedging strategy is designed not to pick prices, but to make sure in the cash flow state a reasonable level. So, that we can optimally size our business, right, so, we are at the cash flows don’t get jerked around so much that you're constantly trying to get fewer rigs or more rigs, fewer crews or more crews. Craig Shere – Tuohy Brothers: Right. So, cash flow certainty not necessarily rate of return certainty particularly at low gas prices. When you make this decision, are you basing it more on like the current strip of 12 months? Are you basing it on the next 10 years of strips?

Well, generally, just ballpark we are typically within more of a five-year strip, but if the price – I think you'd say in theory and we do try to apply some of this. But you try to hedge not to guess prices, but when certainty about price would alter the behavior or when uncertainty about price would alter the behavior. So, I wouldn’t say that we don’t take returns into our account back. I’d say if there is projects were buy, it’s an attractive investment if prices are at the current level, but prices decline it's not attractive anymore, but that's the time we say yes, best decision is to go ahead and make the investment, but also hedge. Craig Shere – Tuohy Brothers: I got it. Okay, it doesn’t sound simple, but it sounds like you have a lot on your plate to manage the portfolio there.

No, but I think a lot of hedging is that, right it's more or like, I guess it's expected utility as suppose to expected value is what we’re looking at. It’s kind of the same as what you’re looking at the life insurance, right? So nobody buys life insurance hoping that it pays off. Craig Shere – Tuohy Brothers: Sure.

Well, at least start soon. Craig Shere – Tuohy Brothers: Well, hopefully, well we get out of this throughout with gas prices and you can enjoy the benefits of the entire portfolio.

Yeah again, we do think that we need to be structuring our business and what we pursue is for investment opportunities with a relatively conservative gas price in mind, not to say this one is influenced by the current storage situation. But that – it’s getting more economical to drill for natural gas at least in our base in the Marcellus, but I guess, we can see the other bases and we need to bear that in mind what we’re forecasting our dividends. Craig Shere – Tuohy Brothers: Understood. I appreciate all the color.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks. David Porges – President and Chief Executive Officer: Thank you for everybody for participating and we’ll look forward to doing this again in three months. Thank you.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.