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Ultra Petroleum (NYSE:UPL)

Q1 2013 Earnings Call

May 03, 2013 11:00 am ET

Executives

Michael D. Watford - Chairman of the Board, Chief Executive Officer and President

C. Bradley Johnson - Vice President of Reservoir Engineering and Development

William R. Picquet - Senior Vice President of Operations

Douglas B. Selvius - Former Senior Vice President - Exploration

Analysts

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Stephen Richardson - Deutsche Bank AG, Research Division

Mark P. Hanson - Morningstar Inc., Research Division

Raymond J. Deacon - Brean Capital LLC, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

James C. Roumell - Roumell Asset Management, LLC

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Michael Chapman

Operator

Good day, ladies and gentlemen, and welcome to the Quarter 1 2013 Ultra Petroleum Corp. Earnings Conference Call. My name is Tamlyn, and I'll be your operator for today. [Operator Instructions] As a reminder, the call is being recorded for replay purposes. And now, I'd like to turn the call over to Michael Watford, Chairman, President and CEO. Please go ahead, sir.

Michael D. Watford

Thank you. Good morning, and thank you all for joining us today. With me today are Mark Smith, Senior Vice President and Chief Financial Officer; Bill Picquet, Senior Vice President, Operations; Brad Johnson, Vice President, Reservoir Engineering and Development; and Doug Selvius, Vice President, Exploration.

I'd like to point out that many of the comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are disclosed in more detail in the Risk Factors and Forward-looking Statements sections of our annual and quarterly filings with the SEC. Although we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website.

Also, we intend to file our 10-Q with the SEC later today. It will be available in our homepage or you can access it using SEC's EDGAR system.

An exciting read, I'm sure.

Well, this morning looks a little different than this time last year. Natural gas prices are $4 per Mcf, not $2. We are generating free cash and thinking about new investments as compared to last year's cutting capital and monitoring debt levels. The seas are calm and the sky is clear versus choppy seas and stormy skies last year. And we are doing what we said we would do: let things settle out as we move through the trough of a natural gas commodity price cycle.

So what's new? Well, we had winter. While it was late in arriving, the delayed cold winter weather that occurred in March prompted natural gas prices to recover from a low of $3 in early January to a high of well over $4 in April. Natural gas used for power generation in the first quarter was roughly 3.5 Bs (Bcf) per day above the 5-year average. We withdrew about 2.3 Tcf from storage. And for first time in a number of years, the withdrawal season ending storage balance was below the 5-year average. And we believe the natural gas supply has peaked.

Incredibly, with the massive amounts of invested capital, Lower 48 natural gas production grew from 56 Bs a day in January of 2010 to almost 66 Bcf per day in November of 2012; it's peak. It has declined to approximately 64.5 Bcf per day currently and will continue to decline throughout this year and next. A recent survey over half of the top 20 largest North American natural gas producers set a first quarter 2013 sequential production decline with the remaining after report results.

While the macro economic -- excuse me, while the macro environment has clearly improved, we remain committed to investing our capital wisely and preserving our balance sheet.

Let's review our first quarter 2013 results. Our first quarter production of 59.3 Bcfe benefited from the strong Pinedale wells we brought online late in the fourth quarter of 2012 and early 2013. For the second quarter, we are guiding on production of 57 to 59 Bcfe and anticipate our monthly production volumes to stabilize from now until the end of the year, averaging over 19 Bcfe per month.

One of our goals for 2013 is to be cash flow positive, continuing the trend for 2012. In the first quarter of 2013, we invested $108.4 million of our $415 million capital program while generating $123 million in cash flow. Currently, we are estimating $125 million of cash flow in excess of our capital investment program in 2013.

Looking at our expenses for the first quarter. Our all-in cost of $2.79 per Mcfe, which include cash cost of $1.75 per Mcfe, landed us in the low end of our guidance range as well as the low end of our industry. Our first quarter lease operating expense reflects the full effect of the liquids gathering system rental fee, which also impacts our cash flow margins.

However, our margins remain solid in the first quarter with a cash flow margin of 55% and a net income margin of 26%. Our low cost translate to the low break-even levels. Our first quarter net income breakeven was $2.78 per Mcfe, and our cash flow breakeven was $1.59 per Mcfe.

We reported operating cash flow of $0.80 per diluted share or $123 million for the first quarter. Our first quarter adjusted net income was $0.38 per diluted share or $58.5 million.

Let me update you on our 2 primary assets. In Wyoming, we drilled 26 gross, 11 net wells and brought online 34 gross, 21 net wells. Our first quarter Pinedale production averaged 455 million cubic feet per day, flat to fourth quarter 2012 volumes. We are operating in better areas of the field, evidenced by the strong wells we brought online later in 2012 and continuing in the first quarter. Our first quarter average IP rate for the operated wells brought online was 9.7 million cubic feet per day, which includes a notable completion with an average initial rate of 19.4 million cubic feet per day. The combined fourth quarter 2012, first quarter 2013 average IP rate was 10.2 million cubic feet per day.

Continued completion optimization reduced Pinedale well costs in the first quarter. We achieved a 6% reduction from $4.7 million at year-end 2012 to $4.4 million in the first quarter. And we've updated our Pinedale single-well economics to reflect these lower costs. This year, we are drilling 5 to 6 Bcfe wells in the field and the returns at $4 gas price average 40% to 60%.

Over our decade-plus history in Pinedale, we've diligently worked to improve field operating efficiencies. Now we are focused on improving our percentage of wells drilled in less than 10 days and we've made substantial progress. During the first quarter, we drilled over 40% of our operated wells in less than 10 days, compared to only 3% in 2010. And I think our record is about 8.5 days.

In the Marcellus, we drilled 7 gross, 3 net horizontal Marcellus wells and brought online 17 gross 8 net wells. Our first quarter Marcellus production increased sequentially to 204 million cubic feet per day due to consistent well performance. We indicated on our last quarter call that due to the low natural gas prices, our Marcellus joint venture activity pace will appropriately continue to decrease and that is what has occurred. This time last year, Shell was planning to drill over 180 wells in 2012. Correctly, they reduced their planned program to just over 80 wells and we participated in about 1/2 of that amount. This year, Shell only plans to drill 34 wells, which we expect to participate in about 28 of them. This is good news from an asset preservation perspective.

The non-consent elections we made in the Shell AMI during 2012 were driven in part by the extensive seismic and geologic studies we've completed in order to better understand reservoir performance. In 2012 through the first quarter of this year, the average EUR of the wells we participated in is more than double the average EUR of the wells we non-consented. These decisions were especially crucial during periods of low commodity prices, given the significant impact to returns.

In our other joint venture with Anadarko, no new wells have been drilled on our AMIs since July 2012, and there are no current plans to drill wells in 2013 or 2014. We have significant 3D seismic, spending approximately 500 square miles across our 260,000 net acreage position, which has been beneficial in maximizing the value of our asset. We are planning to acquire additional 3D data of a portion of our 60,000 operated acres in the Marcellus to evaluate the resource and identify potential sweet spots outside of our current seismic coverage.

So as we pause and reflect at the end of the quarter, what's different for us versus the end of 2012 just a few months ago? Well, first, at $4 natural gas, we restore all the value and volume to our proved reserves that got haircut by the trough of the natural gas commodity price cycle. So from an asset standpoint, we're back to 5 trillion cubic feet of natural gas equivalents of proved reserves with a PV-10 value of $5.25 billion. Unfortunately, accounting rules don't allow us to add the value back to our balance sheet, but the value does exist in Israel.

Also, on a larger scale, and probably more important, over 85% of our 17 trillion cubic feet of natural gas equivalents of 3P reserves or 14.5 trillion cubic feet is economic at the same $4 gas price. That goes to our low-cost asset base and operating costs.

Just a few comments about our stock price, which is valued about the same now as it was this time a year ago despite the doubling of natural gas prices that has occurred. There are a number financial and operational metrics one can look at to draw correlations to a company's stock price performance over time. One study issued a few years ago concluded that the best correlation to stock price performance were production for debt-adjusted share growth, change in cash margins, return on capital employed and PV/I.

Looking at our sales through this lens, historically, we performed fairly well on these metrics. And then with a collapse of natural gas fundamentals, our performance in these areas has diminished and certainly our stock price suffered. But now directionally, all those measures are moving up into the right for us and we should see some response in stock prices as a result.

So more broadly speaking, looking forward at today's natural gas futures curve, which remains insufficient to attract necessary capital to support a 60-plus Bcf per day of domestic natural gas supply, we see declining production this year and next when contrasted with significant demand increases in 2014 and 2015, due to growing Mexican exports, LNG exports, the natural gas power generation and industrial demand growth. The implied upward movement in natural gas prices translates to profitable growth, expanding margins and higher return for Ultra.

Thank you. We appreciate everybody participating today -- well, no, we're going to open up for Q&A right now, I'm sorry. I'm getting ahead of myself. So operator, if you're there?

Question-and-Answer Session

Operator

[Operator Instructions] It comes from the line of Noel Parks from Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

I just wanted to ask what's the new 3D seismic you're planning to shoot, do you have a rough estimate of the cost and over how long a time frame you'll be spending that?

C. Bradley Johnson

Well, it's going to get spent fairly quickly. We hope to spend it this year, but we might run up against hunting season but we're trying hard to get it spent this year. The cost will be $3.8 million to $4 million. And it's a 35-square mile shoot that we're designing just to bolt on to our existing 3D in the area that we operate in. And we're looking to do a couple of things. First, as Mike indicated, we want to expand -- we see some seismic sweet spots that extend to the edges of our existing 3D and we want to delineate where those go because they're very high-value areas. And then second, the Utica play is rapidly moving towards our acreage position and we are looking to get a better handle on that geologically.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. And when you talk about it moving towards your position, do you have any -- I'm sure you guys have talked about this before, but do you have any sense of composition of what the production might look like if it works near you?

C. Bradley Johnson

Dry gas, if that's what you're asking, Noel.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Right, right. Okay. And Pinedale saw the really nice improvement in single well economics. And I was just wondering since this is what you've kind of, as I've heard management say recently, in response to you've kind of accomplished about, what -- about all you can on the drilling side, I'm just curious. Your other partners at Pinedale where you're non-operated, are they putting similar resources into improving efficiency in their areas? Or are they sort of disengaged and focused a lot more on other plays right now?

William R. Picquet

This is Bill. No. I'll answer that. Of course, we have the benefit of seeing essentially what almost everybody does in Pinedale because we own an interest and what the other operators are doing typically. And so we get to look at all of that data and utilize it from an optimization perspective whereas the other guys are focused on their operations primarily. And yes, they optimize just like we do, but we have a better bigger data set that we're looking at that gives us some advantage in that respect.

Operator

The next question we have comes from the line of Ron Mills from Johnson, Rice, L.L.C.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Mike, a couple of questions and maybe 9 for you. On the $300,000 cost improvement in the Pinedale Anticline, you talked about that being completion optimizations. Is that about all you think you can do on that side? Do you think there are still more completion optimizations? And can you just provide maybe a little more color as to what you did differently?

William R. Picquet

This is Bill again. We think there's a little more as far as optimization opportunity is concerned. We're experiencing improvements all the time and I guess our answer is we continued to refine things and continued to look at data and very aggressively apply the learnings from data. We're using multi-disciplined teams that just seem to keep coming up with great ideas. So where can they go? I think you'll see that number go down a little bit over the course of the year, but we're also going to be completing in areas of the field where we may need more stages as we get into better areas of the field and quality of the resource improves so you get bigger wells. So cost will vary depending upon where we are in the resource, but we'll never stop optimizing and we continue to get some gains on the drilling improvements as well. But those gains, as we've mentioned before, are getting smaller as far as timing. So we haven't reached the end of it yet but every time we move a little bit more, it gets tougher and tougher.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And then you've talked about drilling in terms of where you're drilling now as one of your better areas. And I know you have to pursue a development plan or at least somewhat related to the BLM. How long will you be more located in this better area? And what's the outlook as we look not just through the rest of this year in 2014 in the Pinedale in terms of where -- what the relative acreage looks like versus the recent results?

C. Bradley Johnson

Yes, this is Brad, I'll answer that question regarding the Pinedale. We expect to be in this area for several years. The Boulder area where we've been drilling over the last 6 to 9 months has generated good results for us. And we've been talking about getting into this area for several quarters and we're happy to be there and we expect to be there for quite some time.

Michael D. Watford

You want to talk a little bit about the most recent results from that one bad Boulder?

C. Bradley Johnson

Absolutely. I think we talked about 1 well hitting 19 million a day in our press release. But the Boulder 5-19 pad, which is right in the middle of development area 3, we brought on 10 wells in the first quarter. And those 10 wells average 13 million a day. And these wells are going to be over 6 Bs. So we're really pleased with those results and we think we'll see these type of results for several years.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And Brad, is that the kind of area that Bill's referencing in terms of a better area you may be doing more stages, or is that maybe a little bit higher cost but more recoverabilities? Or are those the kind of wells that you're seeing the $4.4 million, $4.5 million well cost?

C. Bradley Johnson

I think we're going to be able to achieve $4.4 million cost in this area. And Bill's comments are accurate that as we continue to drill wells in this good area, it may challenge us a bit about getting to $4 million or below because of stage count. But as Bill said, we'll continue to push, and ultimately, we're trying to optimize value and cost is a big component of that. But the 5 and 6 Bcf wells is a great component as well.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And I think you also mentioned that the Utica is moving towards your acreage. Are you talking about acreage you have more on the Tioga-Potter County area or where is that Utica marching towards out of your acreage positions?

Douglas B. Selvius

Actually, this is Doug. I'll answer that. We are talking about the Tioga-Potter County acreage position. The play is moving that way and there's a number of wells that have already been drilled and a significant numbers of permits that are coming across for operators to drill wells in those areas. And we recognize that potential. We've recognized it for several years now. We're just waiting for gas prices to justify exploration for that target.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then one last, just strategically for you Mike. In terms of the free cash flow generation, which you've been able to accomplish testament to your low-cost properties but also just your steadfastness in terms of not throwing good money after bad, is the process or thought process just to continue to pay down debt with that free cash flow up until the time and the structural demand starts to -- and the falling supply outlook that you have starts to really show up in the futures curve?

Michael D. Watford

Yes, more or less, Ron. I appreciate you calling my view steadfast as opposed to stubborn. But yes, we want to generate free cash on a net basis last year. We certainly did in the second half of the year on a monthly basis and we're going to continue that in 2013 till we saw that the movement in the commodity price for us, natural gas. We're seeing part of that move. We think there's far more to go. I mean, it's hard to imagine that you can actually offset once you get through backlog of some of the wells that are in connection to Marcellus and perhaps in Eagle Ford. Hard to see how you can offset 10% domestic decline in supply with the amount of capital we invested in drilling gas wells these days. So I think that we'll be surprised at how it begins to roll off certainly in second half '13 and into 2014 and gas prices out there in forward curve don't support new investment from us, players. We uniquely make a fair amount of money at $4 gas, not at $2 or $3. So we were -- we had a nice, robust conversation, I think, is one term we use internally with the board earlier this week as to what to do with our -- with what we see as free cash this year and next. Our preference right now is to have the third leg of the stool still pretty much commodity-agnostic. We're all about returns. But at $4 gas and where we're going to be drilling at Pinedale the next few years, we got 40% to 60% returns, that's pretty stout, a hurdle to get over. It's hard to equate that even to your $90, $95 oil price from most oil plays, but we are going to look aggressively. We'd probably see more upside in other natural gas opportunities because we think the commodity will be $5 second half of 2014 and not before. But we are -- we've got a couple of balls in here, and we'll just update you a little further as we get a little further down the path, if that makes any sense.

Operator

The next question we have comes from the line of Stephen Richardson from Deutsche Bank.

Stephen Richardson - Deutsche Bank AG, Research Division

I had a quick question, Mike, if you could perhaps address. You laid out a multiyear plan, I believe, in your investor presentation and appreciate that you're working off completions in Pinedale up to the end of this year. But could you just remind us what is that plan as it currently stands implied in terms of if it involve additional rigs in the Pinedale, we could assume additional activity in the Marcellus as you get into '14? And I guess, the second part of that question is what kind of gas price do we need to see in '14 to either make you reconsider that plan, I guess, with a downsize? Is it -- are you looking for a $4.50, $4.75 price or that plan still stands at $4 flat price?

Michael D. Watford

Okay. Well, let me -- it wasn't a plan. It was just -- it wasn't guidance. It was just to show what we could do with existing inventory by investing within cash flow at these gas prices that exist at that time in the forward curve for the early years, in particular the '14 and '15 time period. We haven't committed yet as to what we're going to do in 2014 and '15. If we look back at a plan that we had beginning of the year, we would have suggested perhaps more activity by some of our partners in both plays and that's not going to happen. So if absent -- I mean, our preference right now is to go buy something so we don't actually grow domestic natural gas production -- the gas asset that we grow corporately for we don't grow on a national basis because we want to see supply shrink. And so that's what we're going to do first. Secondly, if that doesn't work out for us in a timely manner, then it's hard to not be aware of the tremendous returns inherent in the Pinedale activity right now. If we're going to be in this area, DA3 as we call it, that's going to afford us the opportunity to drill 5 and 6 plus Bcf wells for the next 2 to 3 years. And at $4 flat gas prices, that gives us 50% to 60% returns. And if we can continue to get well costs down, which drives that return even higher, then it would be logical for us to think about adding resources there in terms of rigs and activity. So I kind of walked you around the world a little bit there without directly answering but just giving you some sort of direction as to what we think we're going to do.

Stephen Richardson - Deutsche Bank AG, Research Division

No, I appreciate that. That is useful in terms of understanding the thinking. So it is fair to say that a hurdle rate on an acquisition would be in that 40% to 60% rate of return on an ongoing basis, is that the right way to think about it? Or is it lower because there's a preference for doing that versus drilling Pinedale wells?

Michael D. Watford

I think it would be lower just because of preference of having a third leg of the stool and giving us another opportunity set to work with. But it can be materially lower.

Operator

The next question we have comes from the line of Mark Hanson from Morningstar.

Mark P. Hanson - Morningstar Inc., Research Division

Two questions. At what price do you guys see Anadarko and Shell returning to the Marcellus in -- if maybe not in full force, ramping up from their current levels? And then how frequently are your plans revisited with those JV partners? And then I have one follow-up.

Michael D. Watford

Well, I think, prices are well north of $5 before you get any significant activity or even get them to look at expanding activity. So you got to see a $5 price out there for good period of time that they're comfortable with for them to even start the planning process and obviously there's a lag behind when they say, yes, we think we would want to start thinking about this when you actually have activity. And we get to talk to them all the time.

Mark P. Hanson - Morningstar Inc., Research Division

Okay. And then my follow-up, can you just remind us philosophically your thoughts on -- I'm thinking about funding a new ventures opportunity if one of those come up that meets your threshold there for acquisition on issuing equity versus debt?

Michael D. Watford

Well, we're not a real fan of issuing equity. If you look at our history, that hasn't happened. Maybe once in 14, 15 years and that was way back when in 2000, 2001. So that's not normally our style especially at the current valuation. We'd have to see tremendous upside in an opportunity to issue equity. So I would think you'd see us do it with free cash we're generating this year and next and possibly a little additional debt although we're not too keen on additional debt right now, but all that changes as commodity prices go up.

Mark P. Hanson - Morningstar Inc., Research Division

Sure. And are you guys still focused on flowing asset as opposed to a greenfield?

Michael D. Watford

Well, it's a preference, but that's hard to do. But it's a preference. But I don't want to turn Doug off, exploration side. I want to be kind to him.

Operator

The next question we have comes from the line of Ray Deacon from Brean Capital.

Raymond J. Deacon - Brean Capital LLC, Research Division

Michael, I was just looking at the IP rate for the Marcellus wells, you reported 5.8 million a day. Can you say where -- I'm assuming most of those were from Clinton and Lycoming because it looks more like the upper type curve, is that right?

William R. Picquet

Yes, that's correct. 14 and 17 wells came from the Clinton and Lycoming area.

Raymond J. Deacon - Brean Capital LLC, Research Division

Okay, got it. Great. And I guess, could you just elaborate a little bit more? To get from 4.4 million to 4 million, can you do that and still see EURs in the Pinedale in that 4 to 6 range? Or is it -- for productivity -- the returns are -- do you think the returns stay the same or potentially improve as you do that, I guess, is the question.

William R. Picquet

We're -- as Brad mentioned earlier, looking at the overall equation as far as value is concerned, so we're not going to sacrifice resource for cost reductions, if that's what you're asking. Bottom line is we've done what we've done so far without any changes for well performance and we intend to continue that.

Operator

The next question we have comes from the line of Matt Portillo from Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. I was hoping that you could give us a little bit more color on your updated thoughts around the Tioga-Potter County type curves in terms of the wells that you did participate in?

C. Bradley Johnson

Yes, this is Brad. I can comment on that. In all areas, Tioga-Potter and then down south in Clinton-Lycoming, our wells continue to perform in a firm, our type curves. Each and every quarter, we strike out the forecast -- strike the forecast forward in our wells and our overall volume were actually turning above that forecast, so the declines get flatter and the wells continue to perform at or above expectations.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so in those wells that you did participate, could you give us an idea of just kind of where those EURs are for the Potter-Tioga acreage?

C. Bradley Johnson

Well, the Potter and Tioga wells that we participate in land right at our average expectation of 4.5 to 5 B wells. The wells that we non-consented are 1/2 of that, so there are 2 Bcf wells out there and Doug's team and the collective teams have done a really good job of pegging the wells that perform poorly and we stand out of those.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And could you give us any idea of just -- of that acreage that you guys have in Potter and Tioga? What percentage you would say is probably prospective for the 4.5 to 5 Bcf type curve?

Douglas B. Selvius

You want me to answer that? For the 4.5 Bcf type curve, almost all of it. There's a small portion in the western part of our JV with Shell where we might be challenged to get there. But in other areas, we exceed that. So on average, probably all of it.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. The non-consent wells aren't a big portion of your drilling campaign?

Michael D. Watford

No.

C. Bradley Johnson

Certainly not a big portion of the entire asset. It was half of the activity in 2012 because of where the rigs were located, but...

Michael D. Watford

So where are the rigs going to be located this year?

C. Bradley Johnson

This year, they're in the better areas and so you can see that by the participation rate that we showed in the press release or at least in the comments earlier, 28 out of 34 so...

Douglas B. Selvius

And I can give a little more color. I know what he's asking. We're making a lot of these decisions based on what we see on our seismic data, and I think this goes to your question. 70% of our seismic is indicating Marcellus sweet spots out there. We're well calibrated and have good data so we see 70% of our acreage having high value out there.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. That's very helpful. And then just my last question. You guys are posting very strong well results in the Pinedale. Given kind of the relative economics of Tioga County, can you give us an idea of kind of how those 2 compares to the 40% to 60% rate of return on economics in the Pinedale versus what you guys would see on your Royal Dutch acreage at the moment?

William R. Picquet

Yes, right now, the Pinedale is the best stuff in our portfolio. And the Marcellus already has the potential to continue to compete once costs get down to reasonable levels. And that's Royal Dutch Shell, specifically. Obviously, the Anadarko has always been one of our better performing areas. We're just not actively drilling there now.

Operator

The next question we have comes from the line of Ted Crawford from Roumell Asset Management.

James C. Roumell - Roumell Asset Management, LLC

This is Jim Roumell. A couple years ago, the majors were really stepping in and buying a lot of gas assets, Exxon and others.,, And it's been quiet during the period where gas is really -- during that period where it really fell, which is kind of curious. And I'm just curious to know whether you're seeing any increased interest among the majors to buy properties and kind of where do you place that in how they've behaved over the past several years?

Michael D. Watford

Well, no, we haven't seen any increased interest in the majors in buying properties. I think they're still taking advantage of the oil opportunities they have worldwide and investing in those and maybe LNG elsewhere in the world where the returns are better. In fact, if you look at Exxon's production, natural gas production, in North America, I think they're down year-over-year by 9% in the first quarter and sequentially from fourth quarter to first quarter 3%. So I mean, their production spend like $340 million a day year-over-year in North America. So I think that suggests to you that they have withdrawn capital, will continue to withdraw capital in North America until they see something much better, which probably means the earliest is 2015. But I don't -- we don't have any inquiries from those folks currently.

Operator

We've no question at this time [Operator Instructions] Next question we have comes from the line of Tim Rezvan from Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

I was hoping to get a little more clarity. You talked about adding a third leg to the growth stool given the $125 million -- partially funded by that $125 million you see this year. Can you talk about what -- when would a board decision come on that? Do you have that approval in hand? And would you think your budget would be limited by that amount?

Michael D. Watford

I'm trying to think if there's any more of those questions I can answer. I can't tell you whether the board's approved something or not, but I don't really have a good timing for it at this point in time. What was the third question there?

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Well, I guess, just curious, how much you might look to spend. I'm just guessing you're not going to give an answer on that either, but it's worth a shot.

Michael D. Watford

Well, in order to do something that would be worthwhile for us, it probably have to be more than $125 million, how's that?

Operator

The next question comes from the line of Michael Chapman from Private Capital Management.

Michael Chapman

Mike, just a quick question on the hedging. You guys historically haven't hedged prices when it's below $4 this quarter. Is that a change in thought process or is that just short term given the volatile nature of gas over the summer?

Michael D. Watford

No, it was a direct response for folks calling and commenting that they were concerned about some debt covenants. And we said, fine. We'll just remove that from discussion. We'll just hedge some our own way. We did it in 2 different efforts at both times. As soon as we hedged, the next day gas prices went up so we weren't very smart about it, I guess, if I want to make -- poke fun at myself. But we did it just to protect the downside during the summer. We're comfortable gas prices are turning up, not down and supplies are trending down, not up. But we just want to take the risk off the table, put it behind us. So if you'll note, we have not hedged anything in 2014.

Michael Chapman

And if it the strip gets to $4.50 or $4.30, would -- does that become more desirable for you guys?

Michael D. Watford

Well, $4.50 becomes more desirable, yes.

Operator

Thank you. That's the end of the questions-and-answers. I would now like to turn the call back over to Michael for closing remarks.

Michael D. Watford

Thank you. I love the way you say Michael, that's great. We appreciate everybody participating today. Should you have additional questions, please contact the Investor Relations group, and then we hope you have a good day and a good weekend. Thank you very much.

Operator

Thank you, Michael. Ladies and gentlemen, that concludes your call for today. You may now disconnect. Have a good weekend.

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