XTO Energy Q4 2006 Earnings Call Transcript

TRANSCRIPT SPONSOR

XTO Energy, Inc.(XTO)
Q4 2006 Earnings Conference Call
Feb 13, 2007 4:00 PM ET

Executives

Louis G. Baldwin - Executive Vice President and Chief Financial Officer
Keith A. Hutton - President
Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Analysts

Tom Gardner - Simmons & Company
Philip Dodge - Sanford Group
Kent Green - Boston American Asset Management
Stephen Beck - Jefferies & Company

Presentation

Operator

Good day ladies and gentlemen and welcome to the Fourth Quarter 2006 XTO Energy, Inc. Earnings Conference Call. My name is Cheryl and I will be your facilitator for today. At this time all participants are in a listen-only mode. However, we will conduct a question and answer session towards the end of this conference. [Operator Instructions].

Before we begin, XTO's management will be making forward-looking statements during this call. Risks associated with such forward-looking statements have been outlined in our latest 10-K, 10-Q and news release. Actual results may vary materially. The company undertakes no obligation to publicly update or revise any forward-looking statement.

At this time, I would now like to turn the call over to Louis Baldwin, Executive Vice President and CFO. Please proceed sir.

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Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Thank you. Thank you for taking your time to join us today to discuss our fourth quarter and 2006 results and the outlook for 2007. I'll note that our Quarterly Operations Review is currently available on the XTO website, and when Keith is going through his comments, you may want to refer to that.

Participating on the call today are Bob Simpson, our Chairman and CEO; Keith Hutton President; Vaughn Vennerberg, Senior Executive Vice President and Chief of Staff; and Tim Petrus, Executive Vice President of Acquisitions. On the agenda, as usual today, I will briefly review the quarter and 2006 results and update you on 2007 guidance. Keith and Tim will then update you on operations and Bob and Vaughn will update on hedging, acquisition and macro environment.

Turning to the fourth quarter results; we had a solid quarter in the fourth quarter of this year, matching First Call estimates on earnings and beating substantially on cash flow. Operating cost, importantly, remained well in hand and hedging continues to benefit the company, especially on the gas price front.

I will note in this quarter that not all the hedging benefit hit in gas price and gas revenue; instead, a significant portion went into derivative fair value gain, and I'll explain a little bit about that later.

Our cash margin for 2006 was the highest in the company's history, cash flow to revenue equaling 67%. Production for the quarter on an Mcfe basis was 11% higher in the fourth quarter of 2005, and I will point out that that was in spite of the fact that we distributed 37 million feet equivalent of gas per day with the Royalty Trust distribution of Hugoton in May of 2006 and then also in September 2006, reversion for production payment associated with the EEX acquisition from 1998, reverted -- impacted East Texas and Freestone Trend revenues by about 7 million per day. So, in spite of that, production was up 11%. For the year, production was up 15%.

Turning to comparison of First Call estimates; on a diluted basis, we met First Call estimates of $1.14 per share and if we had included basis hedging that was deemed ineffective for accounting purposes, gas price would have been 8.02, $0.27 per Mcfe higher than reported. That would have made adjusted earnings $1.19 or $0.05 higher than the First Call estimate and extended the out-performance to that as well as cash flow. This related to ineffective hedges on basis, there were cash settlements related to production for the quarter and did not meet the stringent hedge accounting rules for that, but certainly we'll benefit out the quarter on the production hedges that we had.

On GAAP earnings, $429 million in net income, earnings per share were $1.16 on a fully diluted basis.

Looking at production and average price, production of gas was 1.23 billion cubic feet per day. That's above estimates of top side investments [ph] was 1.225 billion cubic feet per day. Oil also exceeded estimates, right at 46,000 barrels per day compared to 45,000 barrel a day estimate. NGLs 12,365 barrels a day, above estimate, and on Mcfe were about 1.2 above the high end of estimates at 1.58 Bcf per day, also increasing the estimates for guidance for the first quarter, and I think Keith will take through that with his.

Looking at the year, production on gas was up 15%, oil production was up 15%, NGLs up 13%, and again on an Mcfe basis we are up 15% for the year. Natural gas prices averaged $7.82 per Mcfe; that's down from $9.09 in the fourth quarter of 2005 when we had higher prices at that time. Oil was $60.57, up from $49.59 in the same period of last year and NGLs were down to $33.57 from $39.83 for the same period last year.

Looking at a hedging update, we have recently added to our gas hedging position. In total for natural gas, first quarter will average 800 million cubic feet a day at $9.34 NYMEX equivalent price and the last three quarters of the year will be at about 900 million a day at a price of $9.19. This gives us about two-thirds our gas production hedged with prices substantially in excess of $9 for the year.

Looking at oil, 37,500 barrels per day at a price of $74.40 or 82% for the year and into next year, about half the production will be hedged 22,500 barrels a day at $74.26. All of these hedges are done with swaps and most basis is hedged for these volumes.

If we look at revenues and cash flow for the year, total revenues were up by 30%, $4.5 billion compared to $3.5 billion in 2005. Operating cash flow just over $3 billion, $3.078 billion compared to $2.267 billion for last year, up 35% and as I have said, the cash flow margin was up from 65% cash flow to revenues to 67% cash flow to revenue. If we look at it on a per share basis, cash flow was 8.29 for the year; that's up 36% from $6.11 for 2005 and just looking at the fourth quarter, 2.45 cash flow per share, up 21% from the fourth quarter of 2005.

Looking at the gas gathering and processing revenue, it was $9.3 million for the quarter and $44.3 million for 2006.

Turning to our unit cost analysis and guidance for 2005. Production expense was $0.87 per Mcfe. That compares right in the middle of the range that we guided to $0.85 to $0.90 and we are continuing that guidance for 2005. We continue to see the slight -- the benefits of efficient growth in the quarter. We did have slight increases in power fuel and CO2 and in compression and other.

Looking at a further breakout of LOE, or production expense, our labor and overhead was $0.22 per Mcfe, maintenance and workover $0.44 per Mcfe, power and fuel $0.17 and compression and other $0.04, totaling again to $0.87 per Mcfe production expense.

Taxes, transportation and other were solidly within guidance, $0.65 per Mcfe, and we are guiding in the 2007 to 65 to 75% -- $0.65 to $0.75 per Mcfe, in line with an increase in gas price assumption from $7 -- to $7 from 6.50 in our previous guidance. Exploration expense was below target, $0.03 per Mcfe compared to $0.05 to $0.10 guidance. That results from lower dry hole and seismic cost.

DD&A $1.04 -- $0.64 per Mcfe in guidance. We are guiding for 2007 to be $1.65 to $1.75. This is up slightly due to the increased property costs and additional investment in gathering and compression systems. Our AORO line was as targeted, $0.03 per Mcfe, continue to expect that for 2007. If we look at G&A, on a cash basis, we had $0.18 per Mcfe, lower than expected; adding to that $0.06 of non-cash compensation expense relating to FAS 123R, we would be at $0.24, beating guidance.

If we are looking into 2007, and we are going to start breaking these two items out, so it will have a little better comparability quarter-to-quarter and we are guiding for cash G&A to be at $0.25 to $0.30 for the year, probably start off lower than that the first several quarters and then maybe increase as we go through the year. And then the non-cash component is expected to be $0.08 to $0.12 per Mcf.

Interest expense, $0.32, beating guidance of $0.34 to $0.36 per Mcf and we're guiding for '07 of $0.32 to $0.34. That interest expense does include for the quarter $6 million of capitalized interest and for 2006 in total $18 million capitalized interest.

The fourth quarter did benefit from a lower effective tax rate, 35.1% versus 37% guidance. This resulted from improved state tax rates, primarily a lower Texas margin tax than originally calculated, and we are guiding to $0.37 per Mcfe -- excuse me, 37% of taxable income in income tax for 2007. The current portion was down substantially as we benefited from higher development expenditures, higher IDC, only paying 6% of tax liability in current compared to 45% estimated guidance. Looking into next year, we still expect up to 45% of our taxes to be paid currently.

Looking at the capital expenditure line. We'll be coming out in the next week or so with our reserves and cost incurred table so you can get actual numbers from that. But just looking at the fund statement, our development costs for the quarter were $492 million, undeveloped acreage $61 million, producing property acquisitions were $104 million and gas gathering, processing and other asset additions $181 million. Total capital expenditures on the fund statement for the fourth quarter $838 million.

If we are looking at the calendar year 2006, development cost $2.037 billion, undeveloped acreage costs $170 million, producing property costs $447 million. This excludes $102 million in stock consideration paid for the Peak acquisition as well as deferred tax step up, so that number will evolve as you get your costs incurred table. And then finally, $379 million in gas gathering, processing and other asset additions.

If we look at the balance sheet, it continues to strengthen in terms of debt to cap. This is the strongest in the company's history. We have shareholders equity approaching $6 billion, $5.85 billion, $6 billion and a debt to total cap of 37%, again, the strongest in the company's history.

With that, I will turn it over to Keith and Tim to talk about the operating review for our fourth quarter.

Keith A. Hutton - President

Thanks Louis. We take a step back for minute and look at what we did in 2006. We start off the year with a 10 to 12% production growth target. We ended by telling you in January we thought it would be 14%, and actually ended up delivering 15% growth for the year. Most of that's in the drill bit. If we look at our reserve picture, we started off last year with 4.2 Ts of low-risk upside reserves, ended this year with a 74% increase up to 7.3 Ts of upside reserves, mainly driven by Barnett Shale, Freestone Trend in East Texas and the Woodford and Fayetteville shales of Arkansas and Oklahoma.

If we look at this quarter in particular, we beat on all products on the high side of our guidance. All of our areas were up except for East Texas, which, as Louis had mentioned, was down only because of a 7 million a day production payment that we acquired through the EEX acquisition and just now came to fruition out of our volumes in the fourth quarter of this year.

If we step from that to the Eastern Region in particular, production actually was slightly down in the Freestone Trend. We kind of warned you about this at our Analyst Meeting that we were having infrastructure problems inside of the field with higher pressures, mainly from us drilling wells ourselves in areas where we didn't have enough takeaway capacity as far as compression and pipelines go. In addition to that, in the fourth quarter, some of our major takeaway points were taken down for maintenance by major pipelines. So, during the quarter, we used that opportunity to take our own system down and do hook ups of some of these compressor stations. And what I can tell you today is our current volume is around 580 million a day. If you look at the average for the quarter, on a gross basis, it was 560 or so. So you will see the kick in the first quarter from all this work that we did.

If we look at the things that occurred in the Eastern Region in the fourth quarter, we continued with our 20 acre tests. As we said, we completed 34 for the year, the Analyst Meeting had come up with 800 potential locations for 20 acres. One of the wells that we did not talk about it was the Cochrum 23, which is in the Freestone Field, yet another one of the wells we completed here recently. It was about 3 million a day.

If we look at the horizontals, we came up with 200 potential Cotton Valley Lime horizontals that we talked about at the Analyst Meeting. We have drilled two and completed those. We have drilled a third and are currently completing it and should be finished with the drilling of the fourth quarter well here in the next couple of weeks. The next two wells will be shallow zones. We broke up into deep intervals and shallow intervals. One is at 11,000 feet and one is at 14,000 feet with reserves that range anywhere from 5 to 12 Bs or so. The two wells that we have drilled, the Gail King 23H, we have completed two zones. The first zone was about 7 million a day, the second zone 6 million a day. We are currently completing the third. And on the original first well we drilled, the Gail King 22H, it came in at 5 million and kind of one zone. We are currently completing the other two zones in it. So hopefully by next quarter, we'll have full rates out of those two horizontals.

If we flip from the Freestone Trend to the other part of the Eastern Region, we continued with our normal development in the Cotton Valley field, in the Carthage and Decker Switch Fields. Of importance in the Tin number 1, which was a Travis Peak step out where there are no other Travis Peak producing wells within a mile and a half or so, and it came in at 1.8 million a day and we have about 20,000 acres in that particular area for further development.

If we flip from the Eastern Region to the Barnett Shale, production was up on a gross basis 12% quarter-to-quarter; on a net basis, 10% to 223 million a day net. That means the production for the year was up over 50% from January to January. Reserves look to be above 1.3 Ts when we finally come out with our actual final reserve report next week, we're currently drilling with 24 rigs, the majority of them in the core 15 and nine in the non-core area. As we talked about, we had significant Tier 1 wells that have come in very well recently, a couple of more wells in the West Walsh Ranch area at 1.8 million a day and just a well that's come on aboard the last couple of weeks at 3.5 million a day. So our Tier 1 wells continue to outperform what we originally thought they would be.

If we flip from Barnett to Permian Region, most of the growth there driven by University Block 9, Cornell and Russell Field, Devonian horizontals. As we've talked about last quarter, we talked about one well that came in around 1500 barrels a day that showed up in this quarter's volumes and the oil -- we saw our go up almost 1000 barrels a day quarter-to-quarter. That was mainly due to University Block 9. We have continued our development programs in Goldsmith, Yates and the Mahoney Lease Field as well and we drilled our first South Texas operated well, which came in at 11 million a day on a 100% well and we will drill about 5 to 10 of those this year. So South Texas is going to have a lot of upside that we haven't previously really talked about.

If we flip from that to the San Juan region, continuing with our CBM development. Raton has now exceeded 55 million a day; in fact, today it's running about 60 million a day. We upped our target, which used to be 60 million a day, today to 75 million a day and we should drill about 40 wells in Raton this year, continuing performance out of the Uinta

Basin, Ferron coal play with that field now up to 26 million a day and our upside 365 [ph] million a day.

If we flip from the San Juan Region then to actually the Piceance Basin. As we talked about, we have drilled two of our four farmout wells that we need. We have found more pay in those wells than we organically anticipated. We thought it would be 500 to 650 feet of pay; it's 850 to 1000 feet of pay. And some of the deeper zones that we thought might not be developed in our particular area have been well developed. We are currently trying to test those. Wells costs have gone up because of more pay and a lot more completions and drilling the wells deeper to $9 million to $10 million. We believe the reserve ranges have also gone up to 3 to 6 Bs per well. And so we have drilled our third well through 10,000 feet. It's remediate, so we are now drilling into the main pay zone on the third well. We should have two rigs running in the Piceance Basin about mid year and drill 4 to 5 wells during the year.

Mid-Continent Region, mainly driven by overthrust drilling in Arkoma where we have had some of the better wells we drilled in the last year with the well actually coming in at 14 million a day during the year. And in the fourth quarter, we continued that with a number of wells coming in at 3 to 4 million a day and the overthrust driving our volumes in that particular area. Of note is now going to be on our Woodford and Fayetteville Shale play. We participated in 40 Fayetteville Shale wells last year. We are currently setting up to drill our first well probably at the end of the first quarter ourselves and we'll drill 10 or so wells in the Fayetteville Shale. Again, those well are 2 Bcf wells or so, 1.5 to 2, about $2 million well cost. Woodford Shale, we are currently drilling our first well, should have that on line by the end of the first quarter. In that area, we own 30,000 net acres, participated in about 15 wells last year and expect to drill 10 wells as well. And in the Powder River Basin, last but not least, we have drilled 80 wells or so in the Big George Coal play, currently making about 2 million a day and expect to drill 40 to 50 wells additional this year and should see somewhere around 10 million a day by exit rate by the end of the year out of the Big George play.

With that, let me turn it over to Bob Simpson to wrap it up.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Thanks Keith. Thanks everybody for joining us today. We had a great year for 2006 and, just as importantly, we are looking at 2007 being multi-front records in production reserves and cash flow. If we look at our upsides, I think the most important development for the owners outside of the obvious is the reserve picture, which continues to expand and improve.

If we look at our total resource, we have three different categories the way we analyze it with the proved category, a low-risk upside and an additional potential. And if you look at as a total, what you call it, captured inventory, for 2006, we described that as a 20 Tcf potential. For 2007, we are talking about 25 Tcf potential or up 25%, and the largest change is in the low-risk upsides, which increased about 75% from 4 Ts to a little over 7. And so while our reserves that are booked have increased significantly, our upsides are increasing at a faster rate, which bodes well for the future as continued prosperity for the equity owner. We are looking at booked reserves of a little over 8.5 Ts now, up about 12% over last year as well. So that's an exciting development for the owners.

We talked about a good deal, public forum in the last couple of weeks, including our analyst presentation in New York a couple of weeks ago. But if you missed that, I wanted to point that out today so that you can catch that important development. And so if you look at our reserve potential, it's exciting and then if you go from there to our cost structure, which is -- ran reserves at about half the industry cost, we believe, which again leads to great economics for the owner. Now to make the low-risk category that's 7.3 Ts of upside, we don't include a potential in there unless the development cost is less than $2 with the current cost structure. So those are highly economic low-risk upsides and again, almost half of industry cost.

Now if you look at XTO, we are not delivering at sort of the half price finding cost with Ts. I mean, we are not -- we don't pay people half price, we don't drill for half price. What we have is prospects that are twice as good as industry, and so that's the reserves per prospect being twice the industry average. This is how we are achieving half the finding costs, and so that's why we think it's repeatable. It's not isolated, it's not a one-time event and it's not a below-market kind of cost side of a structure where we capture drilling rates at half price or something. Instead, it's the abundance of opportunity with XTO in terms of resource per well, and so that will continue. We look to enjoy that indefinitely into the future, the cost advantage. And with that, the cost advantage, we therefore have exceptional free cash flow and should be an exceptional value creator. It takes about 30% of our cash flow to maintain values. It gives us 70% to grow with, which is over $2 billion of cash flow that we are looking at this year to create value, and that's -- we kind of started out with $6 a share of free cash flow, and if we make that 50% better, that's how we should be able to create substantial values again this year.

Last year, we did the 12% reserve growth. We also distributed over $2 of value or 4 to 5% depending on what stock price to use, and so last year was a great year of value creation for owners. We are looking to duplicate that again this year between reserve development and free cash flow investment. So right now we are looking at significant add-ons, is what we'll do with our free cash flow above drilling. Our drilling program is 2.4 billion. Our hedging is -- we have stepped it up a little bit more. As Louis pointed out earlier, we are about two-thirds hedged and if you look at it on a NEB [net equivalent barrel] basis, it's about 9.83 converting all to gas is 6.1. Gas by itself is 9.19 and then oil by itself is about 74. And weighted together it's about 9.83. And so it's approaching $10, roughly two-thirds of your production.

So with those -- with that type of security, we look forward to records this year. With that we can dill ahead at our steady pace, not worry about -- particularly worry about commodity prices while we deliver our double-digit growth and the fluctuations from month-to-month. Long term, we think it's very robust and bright future; short term, lots of volatility, probably the most volatile commodity as significant as there is. As you -- for example, yesterday it moves around, I think -- the front amount was almost $0.60, so that's 7 or 8% a day, and if the market were doing that, that would be a 1000 point move. So to get a feeling for that kind of volatility and the way you would feel if the market dropped 1000 points. And so it's very volatile and our job is to take the volatility out for our business model, for our owners, for our prosperity. And that's why we have engaged in such significant hedging for this year.

The outcome -- anytime the outcome is uncertain, the volatility is even greater. And what I mean by uncertain is we are in a moment of reflection here or a point of trying to figure out what's building on for the year. Now 2 or 3 weeks ago, people had pretty well given up on the winter, which is probably why winter came, and it came dramatically. And so -- and that's changing the answer. And if you look at the numbers, we went from sort of a hopeless inventory situation almost, a give up situation across the three Ts and the latter part of January, which has certainly impressed and somewhat mind boggling. And now, the way we are recovering, it's looking like certainly we are going to have less storage than last year. In fact, we do have that already, but I think we are 38 Bs or something below last year.

But more importantly, we are looking at 2 or 3 weeks in here that should maybe get us on down storage below 1.5 Ts. If you look at the five-year average, it kind of bottoms out a little bit below 1.2. And so we'll probably have somewhat above the 5-year average, but we won't have the situation of twice the five-year average, and whatever was a possibility looking back three weeks ago. It could be -- it's logical to be 1.4 to 1.5 at this point because given this week's withdrawal where there is some chatter it might be a record. I think if it were, we'd have a little bit of a shock effect like we had last August when we had two withdrawals for the first time in summer. I think what it shows you is the increased volatility again because of residential is a more important component than industrial relative to the past. And therefore weather is going to be -- is more of a factor in demand and weather is more volatile than industrial demand was. So what that says is increased volatility and increase in the price, so the hedging becomes a little more interesting.

Last year we announced that our goal was -- we call it hedging -- but our goal, said our way, is maximize realizations. And so what we are trying to do is achieve higher pricing than just sitting here and letting nature take its course on pricing. And so far so good. We have made a lot of money in the last year, more than we've set out to make because weather has sort of gone the way of the person that's hedging, or certainly without a hurricane season and a relatively warm winter. Even with the current weather, hedging has been very valuable.

So we looked at that to increase our realization, then to protect our prosperities, our goal and we won't always be right. We don't think we will. But we won't engage in hedging unless it's smart for our business model, and so -- and that business model is growth. And so you'll see us continue to hedge to protect that growth and at moments when we think we'll probably get better realizations than just doing nothing, and so. But again, we won't always be right. We have been pretty right so far. We have been right so far, but the main thing I can tell you is that we've protected our prosperity such that thoughts of records 2007, while the industry may or may not share that and so. But I don't know when the industry own XTO, and that's the excitement for my family.

So if you look forward to the future of us, we have been -- we won't belabor this conference call because we have some much communication with you the last month. But we will throw it open for questions and be happy to discuss anything you want to ask.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions]. The first question comes from the line of Tom Gardner of Simmons & Company. You may proceed.

Tom Gardner - Simmons & Company

Good afternoon gentlemen.

Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Hey Tom.

Tom Gardner - Simmons & Company

Hi. In the past, you have indicated that service costs -- if service costs backed off, you would not accelerate drilling. Is this still the case and what does the environment for service costs look like now and have you gone back to your suppliers to push for lower prices?

Keith A. Hutton - President

Well, let's do it backwards. We'll do service costs first. We have gone to our suppliers, and what I'd tell you is most of them are not raising anything. We have secured some rigs recently that are in the 17.5 to $18,000 a day range, were 20 a month ago. Logging costs are basically flat. We have heard from several frac companies they will be lowering cost as many people are clamoring for that plus there is more competition coming in. In addition to that, steel costs have backed off in the last six months about 10%. So all in all, I think from a service cost standpoint, you will see it flat to slightly down during this year and unless commodities take off again and people try to pick up more rigs.

Tom Gardner - Simmons & Company

That's good news. As a increasingly larger and larger cash tax payer, how much does that influence your plans growing through acquisitions as opposed as through to the drill bit?

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

I think you've seen step up drilling partly because of taxes. I mean, it's a factor. It's not the number one factor, but it is a factor and I will talk about that a little bit more. But if you look at -- sort of the second part of your first question is would we step up drilling activity at lower service cost? The answer is if we did, it would be modestly. I mean, we are trying to bring early growth to the owner and trying to bring a blended repeatable growth and if you look at the history of the company, it's been about half drilling and half acquisitions. Now in the last 18 months or so it's been predominantly drilling. Part of that's because of the acquisition market versus our own drill bit finding costs. We have built up -- in the abundance of opportunity that we have built up over the years, if you look at the upsides relative to the reserve base of some low-risk category, it was about in '96, it would have been 10%, now it's close to 90. And so the opportunities for drilling have dramatically increased relative to proved reserves. But if you look at our finding costs of $1.50, $1.60 and you back off about 25% for cash tax savings, which is what you alluded to, you get around $1.20 or so with an acquisition market approaching $3. So that -- and so what that says, that one variable all by itself says only drill. But again, before you only use one variable in your model, you've got to remember that for XTO, one's led to the other and we have a balanced program, so we'll always do both. And then when we talk about a $3 acquisition cost, over time, we have at least doubled reserves and so we are kind of thinking that it's headed towards 1.50 just through our process. So it isn't as far apart as you might think at first blush.

So one's our life blood and the other is an outgrowth of it. What's happened is we did such a good job of building up opportunities that when the acquisition market looked a little overheated last year, we stepped out and went to -- primarily just bolt-on around 600 million, and that's what we are still doing. Now, the first quarter is looking good on bolt-ons. We are looking at several hundred million dollars in the first quarter alone. We've signed up over 100, and we'd like to see that at least twice that, maybe potentially three times that, although we don't know yet. So for us the bolt-ons opportunities have stepped up a little bit and so we will continue to do what we did. Now it looks like we have got excess cash flow of $900 million or something, free cash flow above -- I call it above Hutton [ph] internally, although that's a big machine to feed. And so with that, we have got a lot of opportunity to create additional value or additional production growth, and that's what we'll be trying to do this year.

Tom Gardner - Simmons & Company

One last question, Bob. In the past, you've indicated that sub-$7 gas does not compel capital investment into the industry. How has the service cost deflation discussed earlier touched upon your view of forward commodity prices?

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Well, I mean if you look at -- if the industry has 3 to $4 finding cost, that implies $7 plus for immediate price for just that level of investment. And I don't think service costs are going to pull back to the point that that collapses or something. Even in the downturn, it might pull back 20% maybe, but I am -- but if the industry's finding cost continues to pick up over time, so I think the gas price has to be pretty robust to justify that. Now exactly what it has to be is unknown, but you can -- you all compile everybody's finding costs and all the numbers outstanding have been $3 plus as sort of as categories, whether large companies are integrated in 350 or so. And so the commodity price has to be pretty significant to maintain the activity. Now, ours being about half that, we are trying to take advantage of -- you get exceptional economics within the industry as we think gas prices have to be $7 plus. If we can keep our finding costs where it is, what that means is extraordinary economic performance for us. But I don't think that service costs are going to pull back and have to significantly alter that outcome.

Tom Gardner - Simmons & Company

Thanks guys. I will let someone else hop on here.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

All right, thanks.

Operator

The next question comes from the line of Philip Dodge of Stanford Group. You may proceed.

Philip Dodge - Sanford Group

Yes, thank you. Good afternoon.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Hi.

Philip Dodge - Sanford Group

In your guidance, it looks like your exploration budget is up fairly significantly in 2007. I was wondering if you could comment on a couple of the major projects that are involved in that.

Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Well, on the guidance side, we are guiding to $0.05 to $0.10 per Mcfe, which is what we have had really pretty consistently for the last couple of years. It has more Mcfe. So the budget is up somewhat. And we typically don't hit that as again, we are $0.03 or $0.04 last quarter in terms of specific projects, Keith?

Keith A. Hutton - President

Yeah. And if you really look at it, it's going to be driven by Fayetteville step outs, Piceance Basin drilling and some Barnett step outs. It's really where most of your exploration dollars are going to be spent.

Philip Dodge - Sanford Group

In the Piceance, are you still capitalizing most of the spending?

Keith A. Hutton - President

Yes.

Philip Dodge - Sanford Group

Yeah. So it might not turn out to be an expense.

Keith A. Hutton - President

Correct.

Philip Dodge - Sanford Group

And the other thing, Louis, I didn't hear on the taxes for 2006, whether on the current portion, it was 6% of total taxes or 6% of pre-tax income?

Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Sorry, I should have been more clear. 6% of the total tax owed was current and we had potentially been a little aggressive in current versus deferred in the first three quarters, so you did had some catch up there. And I think looking at going forward, we are still forecasting up to 45% to be current for 2007. But as we got into the final numbers, some of the expenditure categories were higher than forecast.

Philip Dodge - Sanford Group

Yeah, understand. Thanks.

Operator

Next question comes from the line of Kent Green of Boston American Asset Management. You may proceed.

Kent Green - Boston American Asset Management

Great quarter again fellas.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Thank you.

Kent Green - Boston American Asset Management

Piceance Basin, there is a little more elaboration and a lot more pay there in zones. Whether it's still tight or not or how tight is it, any -- and then also a wide variance of, say, reserves per well, 3 to 6, are you trending towards the upper end of that because of the excessive pay?

Keith A. Hutton - President

If you look at it, we said 500 to 650 feet is kind of what we were after. We picked up pay in two different areas. We just had more sand than we anticipated in the main Williams Fork, and then we drilled into some of the lower pay, the Corcoran and Cozzette and so forth, which might be 5 or 10 feet thick in many parts of the basin here. There are a multiple sands in there at 30 to 40 feet. So between those two, we picked up almost 50% more pay than what we thought, sometimes double. That's really what the drive is now from a reserve standpoint just because the gas in place is a little than you thought plus you've got more Exxon wells to look at that were a little higher than our original estimate. So we started off at 2.5 to 4 Bs per well; now we are saying it's 3 to 6. I would say we think it's somewhere in the middle of those two numbers.

Kent Green - Boston American Asset Management

Thank you.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Thanks Kent.

Operator

[Operator Instructions]. Next question comes from the line of Stephen Beck of Jefferies & Company. You may proceed.

Stephen Beck - Jefferies & Company

Good afternoon gentlemen.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Hello.

Keith A. Hutton - President

Hey Steve.

Stephen Beck - Jefferies & Company

I just want to get -- hit on one more thing with the Piceance if I may. Just wondering on the -- you drilled the segment well, I believe, into the Piceance and it was -- the frac was under way. I was wondering if you have an update on that, if it's producing and if so from what zone?

Keith A. Hutton - President

We are trying to produce it right now. Obviously, the weather has been pretty bad in the Piceance over the last couple of weeks. We should have it on line here in the next week or so. We have been flowing water off of it from our initial frac, so we have to go drill out the frac plugs. We did three different fracs on that well in the lower interval. So I don't have a good test for you.

Stephen Beck - Jefferies & Company

Okay, thank you.

Keith A. Hutton - President

You bet.

Operator

There appears to be no additional questions at this time. I would now like to turn the call over to Louis Baldwin for further comments.

Louis G. Baldwin - Executive Vice President and Chief Financial Officer

Well, thank you very much. It has been a pretty short call, I guess, because of the analyst conference last, or two weeks ago. XTO's story continues to be to emphasize efficient, sustainable growth. It's especially in automotive [ph] when compared to our peers, we'll be pursuing our 10% production growth goal with a modest increase in our rig count from low 70s to the upper 70s. With this, we expect, as Bob said, to maintain our finding cost advantage in 2007. We substantially reduced our exposure to commodity price volatility through the use of hedging and, as Bob mentioned, given the days commodity strip, we expect to have another record year in 2007. Thank you very much.

Bob R. Simpson - Chairman of the Board and Chief Executive Officer

Thanks everybody.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes today's conference call. You may now disconnect and have a most pleasant day.

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