EQT Corp (EQT) 2012 Q1 法說會逐字稿

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).

After today's presentation, there will be an opportunity to ask questions.

Please note this event is being recorded.

I will now turn the conference over to Mr.

Patrick Kane, please go ahead.

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 5,300 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 seven 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 1000-6583.

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 actual results to differ materially from the 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 update 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 the 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.

Thank you, Pat.

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 of 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 the pre-tax income in the first quarter 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 oflast year, or a 24% decrease.

The decrease in EPS comes as a result of lower natural gas prices on our unhedged production, lower operating income at Equitable Gas, as result of unusually warm weather and higher depletion rates of 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 deletion rates, decreased by 9% to $227 million for the quarter.

With that, I will go into more detail by business settlement, starting EQT Productions, which continues to generate impressive growth in sale 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 it 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, accounting for 6% of the volumes and 34% of the unhedged revenues in the quarter.

Total operating expense at 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 and imposing an annual fee for a period of 15 years on each well drilled.

The impact fee adjusts 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 the impact fee, again $6.2 million of that represents the retroactive portion of the fee for the 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 was 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 the 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.

Per 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.

Finally, on the Midstream; on February 13th, 2012, EQT Midstream Partners, Limited Partnership, filed a registration statement with the US Securities and Exchange Commission, as we move forward on forming an MLP.

Moving onto Distribution; operating income at 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 when last year when measured by heating degree days.

As a result, total net operating expenses 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 during the winter at Equitable Gas, our distribution margins changed by about $10 million.

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 versuslast 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 projections, factoring in some negative impacts from inevitable unplanned delays or disruptions, such as delays in Midstream projects, permit delays, weather impacts, et cetera.

As a result of the lower forecasted natural gas prices for our unhedged 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're also lowing our 2012 CapEx estimates by $100 million, to $1.356 billion.

We exited the quarter with $745 million in cash on the balance sheet.

No short-term debt, including no cash under our $1.5 billion credit facility.

So we remain in a great position, as far as liquidity goes, for 2012.

And with that, I'll turn the call over to Dave Porges.

Thank you, Phil.

As we have previously communicated, our objective, maximizing shareholder value, is unchanged by changes in the environment in which we operate.

The strategy of accomplishing the optimization of our asset base and prudent pursuit of investment opportunities, while living within our means, is also unchanged.

Our (inaudible) must change when circumstances warrant.

In an environment in which natural gas prices are down sharply, we have already made tough decisions, such as our 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 portion of our West Virginia acreage.

With the liquids uplift, the returns of the West Virginia wells is similar to more prolific dry gas wells in Pennsylvania.

There's always a lag between making such decisions and having those changes show up at cash register, but we're getting some immediate benefits from reducing our service costs, as gas prices have declined.

The cost of a 5,300 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 not show up in our depletion rate until next year, just as last year increases hit this year's depletion.

And our all-in, after-tax IRR estimate is now 29% at the current NYMEX five year strip of $3.66 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, though they are obviously not as attractive as they would be at higher prices.

We believe that prices will begin moving up, once the current storage in balance is worked off, however long that takes.

But we're structuring our Business so that it can thrive in an environment which prices never get above where the back-end of 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 a reduction to service costs.

Though 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 guidance for the year.

That is the fact that our growth versus the same quarter last year is below our annual guidance, is not a result of changes and activities, rather it's just the nature of the Business, given multi-well pads, large compressor stations, et cetera.

Growth is a little lumpy.

We also note that the three highest sequential growth rates in EQT history were in the fourth quarter of 2010 and 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 were lower than they were a few months, due largely to the decline in natural gas prices.

But the reduction in well costs 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 an MLP.

As Phil mentioned, on February 13, 2012, we filed the initial S1 for the MLP, but we recognize that this merely starts the review process with the SEC.

To remind you, the advantages to EQT shareholders of forming an MLP include; maintaining operational control of where, when, and to what specs gathering is built, access to 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 other operational matters; as we told you on the last call, MarkWest is building a processing plant to serve our West Virginia wells.

This plant was originally expected 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 fourth quarter.

We're looking into work arounds that would improve on this, but believe that we will meet our production sales volumes targets even with the current schedule.

The real impact of is not on the overall volumes, but rather that additional margins from the revenue uplift expected from liquids extraction at the plant will obviously be delayed somewhat.

We're also working to ensure adequate processing and transportation capacity to support our Marcellus grid beyond this year.

We have an anchor tenant taking 150,000 decatherms per day on Spectra Energy's Texas eastern pipeline expansion to eastern Pennsylvania and mid-Atlantic markets, plus 150,000 decatherms of (inaudible).

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 we're doing what we should to increase the value of your shares.

We will stay 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 your continued support.

Thank you, Dave.

That concludes the comments portion of the call.

Emily, can we please now open the call for questions?

(Operator instructions).

And our first question will come Neal Dingmann of SunTrust.

Please go ahead.

Morning, guys.

Guys, first, can you address the differentials that you are seeing, going forward?

And then secondly, as you talked about the MarkWest deal that likely signed up, how do you perceive the infrastructure cost, going forward, if that deal is successfully completed?

When you say about what changes are, going forward, you're talking about the infrastructure side?

Correct.

Randy, do you want to comment on where you see infrastructure headed?

With respect to the pricing, we have not seen a great deal of softening in the market from that standpoint.

In terms of the projects that EQT is working toward, we continue to be on time, on budget with our Sunrise expansion and building out the infrastructure to connect to the plant.

And as Dave alluded to, we're looking, in the interim, to other options as well, to move -- to get our gas processed.

We're obviously going to see average gathering rates decline even at a constant cost environment, just as the mix continues to move towards the Marcellus.

We've mentioned in the past that the unit rates for Marcellus are roughly half that for Huron.

As the mix keeps moving, we'll continue to see average declines, even without a -- because of the mix change alone.

Okay.

And going for one last question.

On the improved techniques that you're continuing to see, as far as what do you see now as opportunities-wise, on a percentage -- does that continue to expand?

And maybe cause on that going forward, are you able to -- as you continue to do more of these new processes, bring down cost a bit on that completion?

I take it you're talk about production, so we'll turn that over to Steve.

I assume you're speaking about completion techniques, in particular?

Yes, exactly, Steve.

We continue to feel good about the results we're seeing with the new frac techniques, specifically in the more brittle areas, like we talked about.

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're seeing.

So that's been a big benefit, as well, that the cost for the new technique has come down, along with the overall costs.

And then one of your peers talked about the tighter, denser space.

Is that something, Steve, that you're also looking into?

And do you assume it look like -- they talked about increased rates based on that.

Is that something that's you're looking at doing, as well?

Well, I would say we pioneered that.

Yes that's what we're talking about, Neal.

That's what we've been talking about for the last year and a half.

I guess what I'm asking is, Steve, as you continue to, on these pads, do that, is that a basically majority -- right now it's out of -- I don't know what percent of your total program that is, I'm just wondering, overall, if that will become more mainstream in the later part of the year for you.

We still believe that it will be location-specific, based on the brittleness of the rock.

Our current estimate is that for 2012, 44% of our 132 wells will use that technique.

Wow, okay.

In some of the cases, in certain pricing environments, it doesn't make sense.

And in other pricing environments it does make more sense.

Depending on where natural gas prices go, there's kind of a gray area.

There's some where it always seems to make sense, others where it never makes sense, and other places where it's a little bit more sensitive to current economics.

You can see that percentage moving up and down.

Though I would say, Neal, when I look at the things that our folks are doing, they keep working on ways to come up with the optimal completion technique for each of the area in which we're working.

Whether it's the tighter spacing, which, we've been talking about for -- that's we're talking about now when we talk about (inaudible).

That's what we've been talking about for the last year and a half or thereabouts -- or other techniques.

No, it still sounds like that, combined with your longer laterals, you're seeing some of the better results out there.

Thank you.

We'll keep working on -- ever working on trying to get better and better.

Perfect.

Thank you.

Our next question from Scott Hanold at RBC Capital Markets.

Please go ahead.

Thank you.

Good morning.

A question for you, on your drilling program in the Marcellus;obviously, with the gas prices where they are, you've made the case that your economics are still good, and that implies, at this point in time, you're not going to make a change to your overall development program.

But can you talk to the extent where you're shifting -- or have the capability of shifting activity more to liquids from the dryer gas parts of the play.

How much of that is actually going on, at this point in time?

We're shifting to the extent that we can.

You obviously only get the uplift, and this is true for everybody, not just us, you only get the uplift when you are actually able to extract enough of the liquids.

You can get a certain amount of the uplift just from the so-called JT skids, where you -- but they're mainly designed just to get you to pipeline quality gas.

There's cases where that can push it over into that, making it more economic than a 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.

We keep moving in that direction as much as we can, but we're marrying the production activities with the midstream activities.

So does the delay in the MarkWest plant, to a certain extent, limit your ability to really focus a little bit more efforts in those areas?

No.

Not right now.

Realistically, a well that we spud right now -- it does affect cash flows in 2012.

We mentioned that in the prepared remarks, and that's true.

But those are on wells that had already been spud.

For decisions that we're making to spud wells, the presumption is that we have every reason to believe that plant will be up and running and probably some of the increased capacity that we've made reference to would be ready as well.

Because there is this lag between the decision to spud now, as opposed to when it comes online.

No, I wouldn't say that that plant does not impact the decisions that we're making on where to drill right now.

The delay there impacts, really, third quarter cash flows.

Okay.

And then referring to the earlier part of the question that I had, is he looking to back half of 2012, into early 2013, I'm not sure what you are assuming for gas prices, but are you making a 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?

We work with any number of processors, we just want to get the liquids extracted from the gas, so we get the revenue uplift from the propane and butane.

How much is it?

We talk about one plant in northern West Virginia.

But more broadly, yes, 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 ones that are more prolific, which really means the dry gas areas that have the best economics.

Yes, and if memory serves me, that plant, specifically with MarkWest that we're referring to, was 100 million a day.

Our capacity on that would have been -- actually is 120 million a day.

Okay.

120 a day.

How much of an impact will that shift have -- 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?

Pat, do we have a good answer for that?

On an Mcf basis, the liquids uplift gives us about $2.50 increase.

At today's prices.

At today's prices.

And that's $2.50 per Mcf?

Yes.

On an Mcf basis.

One last quick question.

Phil, I think you mentioned what your cash balance was at the end of the year.

I apologize, I missed that.

It was at end of the first quarter, by the way, I'm sorry.

$745 million was at the end of the first quarter.

Yes.

$745 million.

Thanks, guys.

Our next question comes from Anne Cameron of BNP Paribas.

Please go ahead.

Good morning.

Not to beat a dead horse on the West Virginia wet gas issue.

But what is the current West Virginia wet gas production from the Marcellus on an Mcfe basis?

Geez, I don't know if we provided that.

We don't provide the break-out on Marcellus by state.

Okay.

So what I'm driving at is, when the MarkWest does come online, is 100 net enough to handle all of your wet gas production?

And how much more processing do you need?

As we keep growing, we'll need more and more.

And we're currently working on -- and we're well into development on what those alternatives are to keep processing more than the 120.

Okay.

And do you have capacity in the second [Mogley] plant?

Yes.

We have a firm right to 120 million a day of the plant, and MarkWest is putting in a larger plant, and we're in discussion with them and others about additional.

I would reference on capacity on the pipe, as well though, as we said before, we've been proactive, we're adding 100 million a day of capacity, we'll have a total of 100 million out of our Doddridge County.

And at year end, out of our other wet area in Winslow, another 100 million.

And with our Sunrise project, we have adequate residue gas to move that gas to market.

We've been proactive in doing that.

And when the plant comes on, we'll be prepared to move the product, going forward.

As Dave alluded, we're working toward getting additional processing capacity at this time.

We're not concerned about that over time.

The issue is when plants come in, it can move things by a quarter here or there.

That's the issue.

It's the near term cash flow forecast, not the longer term strategy that gets impacted.

Okay.

Thanks.

And that $2.50 uplift, does that correspond to 1.8 gallons per Mcf, excluding any ethane?

Yes.

That's about right?

Okay.

And is the $2.50 net of processing fees or is it gross of processing fees?

It was net.

Okay.

Got it.

Thanks.

In terms of the ethane, can you mix ethane indefinitely, from what you can see right now, into the gas stream?

This is Randy.

From what we can see right now, we have the adequate mix to mix the dry to meet our pipeline specs.

And as we said previously, we'll make the decision on whether to take the ethane based on economic conditions, not on pipeline quality issues.

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 decide to extract it?

Our commercial arrangement with MarkWest provides the option that they would extract the ethane and move it.

Practically, what it means is it would take from that plant and it would really just shift the whole thing up to their -- one of their fractionation facilities.

So really that infrastructure already exists.

It's just a question of making the determination that it's economical to extract the ethane.

Got it.

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, is the game plan to grow third party volumes with that business?

Or is it really mostly just a process to get -- ?

The General Counsel is looking at us shaking their heads.

Oh, he's frowning at me, too.

Okay.

We don't want to say anything that would make you more likely to buy a unit.

Okay.

I'll back off.

Sorry, guys.

That's it for me.

Our next question from Michael Hall of Robert W.

Baird.

Please go ahead.

Most of my question have been answered.

A couple remaining ones for me.

You talk about strategy not changing despite current environment, which makes sense.

But are there any other tactics that you're reviewing currently, that we have not talked about outside of just drilling additional liquids rich wells?

Any other sorts of cost saving initiatives or things along those lines that are currently under consideration?

Yes, we certainly continue to look at ways to improve cost structure.

And, of course, before I alluded to production, but the same thing is true with Midstream, continuing to improve cost structure.

I'm not sure that I feel comfortable getting into the things that are simply in development stage now.

Because we often look at different alternatives, and you test them out, and you see what works and what doesn't.

Got you.

And 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 it's been likely to just be in a dry window.

Is there any indication that, as we better understand the window, is there some wet gas in that as well?

Or is there no real change there?

Thanks.

Not really.

Maybe there is, but there really hadn't been much change there.

We haven't spent, frankly, too much time focusing on that.

The large part, though -- of course it's also deeper in Pennsylvania than it is in Ohio.

Our approach on the Utica still pretty much what it was for our Pennsylvania acreage.

Which is that there is going to come a time when it makes sense to drill down basically from the same pads as we're 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, et cetera.

And when we get to that point in time, that will show cost structure improvements, too.

Okay.

That helps.

That's all I've got.

Thank you very much.

At this time, we'll take a question from Craig Shere, Tuohy Brothers.

Please, go ahead.

A couple of follow-ups on the frac geometry from Neal's question.

First, if I remember correctly, when you all first announced that, it was said that it might add maybe $1 million per well in cost, but you're obviously noting that service costs are lower, currently, so that's really helping a lot.

First part, do you have an updated figure for how much more it costs per well to employ the new geometry?

And to the extent, Dave, you commented that 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 play into any expansion of this program?

On the first part, the costs for the new frac, the additional costs per well is about $1.2 million for the 5,300 feet.

That's down from $1.4 million previously.

Okay.

On the price side, generally speaking, I would say that the areas where it's a gray area whether it makes sense or not, they tend to look better when prices go up.

If you want to look at any company, as say one big derivative as it were, then you would say it's almost as if there are these call options are embedded -- long call options on gas prices.

We tend not to really factor that in too much in the hedging.

There's a longer term play.

But you're right, that does suggest -- if prices are higher, that you'd have more exposure.

So that is true.

But I don't know that I'd say that we formally incorporate that when we're looking at our hedging strategy.

For the most part, the hedging strategy is designed not to pick prices, but to make sure that cash flows stay at a reasonable level so that we can optimally size our Business.

Right?

So we don't have to -- so 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.

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 the current strip of 12 months or are you basing it on the next 10 years of strips?

Generally -- ballpark, we're typically looking at more like a five-year strip.

But if the place -- 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.

I wouldn't say that we don't take returns into account.

In fact, I'd say if there's projects whereby it's an attractive investment if prices are at the current level, but if prices decline it's not attractive anymore, then that's a time where you'd say, the best decision is to make the investment but also hedge.

I got it.

Okay.

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.

It's more like, I'd guess you'd say, expected utility as opposed to expected value, is what you're looking at.

It's kind of the same as when you're looking at life insurance, nobody buys life insurance hoping that it pays off.

Sure.

Or at least not soon.

Well, hopefully we'll get out of this rut with gas prices and you can enjoy the benefits of the entire portfolio.

Yes.

Though again, we do think that we need to be structuring our Business and what we pursue as far as investment opportunities with a relatively conservative gas price in mind.

Not to say this one is influenced by the current open storage situation.

But it's getting more economical to drill for natural gas, at least in our basin, in the Marcellus.

I guess we can't speak for the other basins.

And we need to bear that in mind when we're forecasting our activities.

Understood.

Appreciate all the color.

This concludes our question-and-answer session.

I would like to turn the conference back over to Management for any closing remarks.

Thank you, 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.