XTO Energy Inc. Q2 2009 Earnings Call Transcript

XTO Energy Inc. (XTO)

Q2 2009 Earnings Call

August 5, 2009 12:00 pm ET

Executives

Louis Baldwin – Executive Vice President and Chief Financial Officer

Vaughn Vennerberg – President

Keith Hutton – Chief Executive Officer

Bob Simpson – Chairman and Founder

Tim Petrus – Executive Vice President of Acquisitions

Analysts

David Heikkinen – Tudor Pickering & Holt

Subhash Chandra – Jefferies

David Tameron – Wells Fargo

Tom Gardner – Simmons & Company

Scott Hanold – RBC Capital Markets

Nicholas Pope – Dahlman Rose

Phil Dodge – Tuohy Brothers

Kent Green – Boston American Asset Management

Presentation

Operator

Welcome to the second quarter 2009 XTO Energy Inc. earnings conference call. (Operator Instructions) 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 statements.

At this time, I would like to turn the presentation over to Louis Baldwin, Executive Vice President and Chief Financial Officer.

Louis Baldwin

We'll update you on another outstanding quarter for XTO and share our outlook with you for the balance of 2009. As usual, participating here in Fort Worth are Bob Simpson, our Chairman and Founder, Keith Hutton, Chief Executive Officer, Vaughn Vennerberg, President, and Tim Petrus, Executive Vice President of Acquisitions. To start, I'll review the second quarter results then turn it over to Vaughn. He'll give you his perspectives. Keith will then give you an operational update, and finally, Bob will wrap up.

Looking at the second quarter results, and especially comparing to second quarter of 2008, production was up 32%, total revenues up 17%. Adjusted net income was down 8%. Operating cash flow, importantly, was up 23%, as increased production and lower cash expenses per unit drove that significant beat. And, operating cash flow per share was up 10%.

We're proud of these results, which reflect a strategy that provides prosperity through a variety of economic times. To show just how impressive this performance was, let's look at the price environment for the comparable quarters. This time, for the second quarter of 2008, gas prices on a NYMEX basis, averaged $10.93. They're down 68%. Oil is down 52%, and yet, XTO posted these excellent results.

We think these results show clearly the benefit of the 2008 acquisitions. It's the whole package of the strategy that includes hedging, a strong balance sheet, and consistent production growth. It means that XTO is poised to enjoy record cash flow for this year and continued prosperity into 2010.

Using the 2010 strip in our current hedges, XTO's gas prices are expected to be nearly $7 per Mcf next year, and our oil price will be about $95. Our strategy allows XTO to profitably grow 10% internally this and next, and most important, substantial free cash flow, more than $2 billion this year. And, we can see an additional $2 billion of free cash flow the next year, given the strip prices.

Looking at the financial results in a little more detail, we beat the first call estimates on the diluted basis, $0.82 and our adjusted actual was $0.86. On a GAAP basis, $496 million in net income and that on a diluted basis is $0.85 per share.

The adjusting items were a next derivative of value loss of $18 million after-tax, and a gain on extinguishments of debt of $5 million after-tax. So, as adjusted, we earned $509 million for the quarter. Just to touch on the gain on extinguishment of debt, we did repurchase $86 million in debt during the second quarter.

Looking at production and price comparison, natural gas production averaged 2.352 Bcf per day, 31% increase. Oil just over 69,000 barrels a day, a 35% increase compared to the second quarter of 2008, and natural gas, 20,723 barrels equivalent per day, a 33% increase. So, on a Mcfe basis, we averaged 2.891 Mcfe per day, 32% growth.

Of this growth, 19% comes from acquisitions and 13% comes from development. So, the 32%, you can see how that's broken up. And critically quarter-over-quarter performances were up 6% production on Mcfe basis, all of that 6% came through development.

Our prices for natural gas $7.08 for the quarter. That's down from $7.24 for the first quarter of this year, and down from $8.51 for the second of last year. Oil, $107 that's actually up from our realized price last year of $90.89, and natural gas liquids, $25.52 per barrel. That's down from $58 last year.

One thing to focus on, natural gas basis has continued to improve. If we look at the decrement over NYMEX to our realized price before hedging, it was $1.49 in the fourth quarter, $0.75 in the first quarter of this year, and down to $0.25 in the second quarter of this year. So, as prices have dropped, you have had a declining decrement also, which has improved our realizations on the relative basis.

Looking at revenues and cash flow, total revenues were $2.273 billion up 17%, operating cash flow, $1.514 billion, that's up 23%. We continue to enjoy substantial cash flow margins 67% for the quarter, and our cash flow for Mcfe was $5.75.

Looking at a cash flow per share, we were $2.61. That compares to the second quarter of last year of $2.38, as I mentioned, 10% increase. And, our gas gathering prices and marketing margin was a negative $1 million for the second quarter of this year. That compares to a profit last year of $17 million. That really relates to the narrowing of basis spreads, and when you see higher basis, we typically generate a substantial margin there. As basis tightens, those margins contract, significantly.

If we look at our unit cost analysis and guidance importantly, and Keith will talk about this a little later, production expense was $0.94. That compares, per Mcfe, to $1.00 to $1.05 guidance, so a substantial improvement there, and we've lowered our guidance to $0.95 to $1.00 going for the remainder of the year.

If we look at breaking out that $0.94, labor and overhead compared to the first quarter, was $0.24 and that's down a penny. Maintenance and work-over was the largest amount of decrease. That's $0.55 per Mcfe that's down $0.06 from the first quarter of the year, and then power and fuel was $0.10, that's down $0.03. Compression and other rounds out the production expense at $0.05, so those four items total to $0.94 per Mcfe. And you can see there's substantial benefit there from lower maintenance and work-over [inaudible].

Tax and transportation and other, $0.64 per Mcfe in the middle of our guidance, we are reducing our guidance slightly to $0.60, $0.65 per Mcfe for the remainder of the year. Exploration expense, $0.07 per Mcfe, that's in the middle of guidance and it is down from the first of this year, due to lower dry hole expense and seismic costs.

DD&A increased for the quarter, $2.98. That compares to our guidance of $2.90 to $2.95, and that higher DD&A rate was due to increased production from higher DD&A areas, in particular, looking at offshore production and Bakken Shale production. We're increasing our guidance slightly to $2.95 to $3.00 for the remainder of the year.

Asset retirement obligation, $0.04 in the middle of guidance, cash G&A, $0.21 and that's below the bottom end of the items, but we're keeping that guidance consistent at $0.25 to $0.30 per Mcfe, and non-cash stock-based G&A, $0.16 cents in the middle of guidance there, and no change.

Interest expense was a beat lower than expected. We had expected $0.56 to $0.60 per Mcf. If you look at $0.48 was the actual. That did include the gain on extinguishment of debt, but even including that debt, with $0.51 in interest expense per Mcfe. And we are lowering our guidance to $0.53 to $0.57 going forward, and that relates to lower interest rates, as well as an improvement in expected balances outstanding.

Cash income taxes were 45% of the total income tax, and the total income tax effective rate was 35.8% compared to 37% projected, and we're keeping that projection consistent going forward. If we look at investment in investing activities, statement of cash flows and development costs $828 million. Our property acquisition is $54 million. Gas gathering additions $153 million. And other asset and property acquisitions, $19 million. In total, that comes up to investing activities of $1 billion and $54 million.

Now this is dropping rapidly from the levels that we saw in the first quarter. Keith will update you on that. But we expect continued declines as we go through the year.

Looking at the balance sheet, everything is very similar to what we saw at the end of March. Our long-term debt has increased very slightly to $10.4 billion. Stockholders equity is about the same at $17.6 billion. And what has happened there is because we book our hedging mark-to-market, the OCI, other comprehensive income, is the category that receives that benefit. And as we realize those hedges on a production month basis, the benefit goes into cash revenues and net income and shareholders equity and comes out of other comprehensive income.

Net debt to total cap for the year or for the year at 630 was 37%, again, a very strong performance compared to our historical, and if you look at it without other comprehensive income, less than 40% at 39.8.

With that review, I will let turn it over to Vaughn Vennerberg.

Vaughn Vennerberg

As Louis indicated, again, we continue to be very well positioned for future growth through our activity in 2008 and also the hedging program that we benefit from today, as well as through 2010.

If you look at our guidance release where we indicate our hedge position for 2010, oil production up to 70,000 barrels per day, it should be noted that of that 70,000 barrels per day, long [inaudible] average of 9570, 23,000 barrels of that we have also taken care of with the West Texas sweet and sour differential of $3.43 for all of 2010. So what that does, that guarantees that price for us through that year without any variations in the market.

We also have in place with our hedge and natural gas production approximately 95% of the basis differential locked in for the balance of 2009 and 2010 at between an average of minus $0.36 for 2009 and around $0.26 on average for 2010. These volumes are both the physical and financial hedge volumes combined.

Let me turn right quick to what we all are watching in the issues in Washington to date and let you know what we at XTO are doing to affect the outcome of issues that could affect our business. As you know, the debate on climate change and cap and trade, the House passed that legislation on June 26, after major amendments at 3:00 am in the morning, where they added anywhere between 3 and 600 pages to their legislation.

It certainly didn't give the members much time to review it, but it did pass the House by a vote of only seven individuals, 219 to 212. And of course it creates a system of credit drain by which industry purchases the right to emit greenhouse gases beyond established limits.

The House is in recess at this time and the Senate will recess for a month beginning next week. No doubt the issue of climate change and cap and trade will be on the Senate's list of things to address when they return.

At XTO, we believe the Senate may have an appetite for discussion on climate change, but really the cap and trade model seems to be losing its luster among several among several Democratic leaders. For example, Senator Byron Dorgan, the Democrat from North Dakota, he's the Chairman of the Appropriation Subcommittee on Energy and Water Development, has been very vocal on that point and has gone as far as to say that he has very little interest in consigning our low carbon future to a trading system of carbon securities that will be controlled by the biggest trading companies in the world.

He has also added that it will be a field day for speculation, which I think is not in the best interest of this country. So if you look that common long without their legislative leaders that bodes well for our industry as we deal with the challenges today in Washington. And also helps that we have leading Democratic senators from the oil and gas producing states.

If you look at Senator Max Baucus, a Democrat in Montana, he's Chairman of the Finance Committee. You look at Kent Conrad, Democrat - North Dakota, Chairman of the Budget Committee. Jeff Bingaman, Democrat for New Mexico, Chairman of Energy and Natural Resources. All these individuals are looking at this very seriously, and we are working with them on a day-to-day basis regarding this pending legislation.

Senate Leader Reid has imposed a deadline of September 28 for committee work to be completed. But as usual, with our elected leaders, the process that follows that deadline is somewhat unclear at the moment. During the August recess, myself and others at XTO we are planning on meeting with members of Congress to discuss climate change and other issues.

Secondly, one of the issues in the House climate bill is commodity market regulation. While the stated goal is to curb behavior by multiple speculators and bring stability to the energy markets, we are working to preserve a market that is conducive to hedging.

XTO is working with the legislature to preserve a capitalized market system that enables us to continue to manage risk and protect cash flow. Our work on this issue includes individual lobbying efforts, pointing out the benefits of hedging programs, such as XTO's and our peer companies, as well as joint efforts with industry coalitions and trade associations.

We as a company, we're working very hard to educate legislatures on how we utilize hedging and to preserve a market where it can be used as a risk management tool. This is really one of the many issues Congress is interested in addressing, but really time will be a factor. They are going to begin feeling the crunch of limited time as they resume their work this fall in September. And also, they're going to hear from their constituents as they meet with them during the month of August. And I think that the constituents will be very vocal about what they want to see passed and not passed.

Thirdly, some of the Congress in Congress are proposing a federal program to regulate and permit hydraulic fracturing. We believe strong evidence exists to indicate that this is not necessary in order to protect groundwater and keep drinking water safe. While it's very highly debated, this issue appears to be headed towards an EPA study.

States have adequate regulations in place to seal off and protect drinking water tables from oil field injection practices. And so our hope is science and a better understanding of the industry efforts to isolate drinking water bearing zones, will put this issue to rest. Until then, we'll continue to be engaged in the discussion. Representative DeGette from Colorado and Representative Hinchey from New York are the authors of this bill and we do think it may go to an EPA study.

As we continue to meet with members of Congress during this recess, we will also be talking about these issues and setting the stage for an anticipated discussion on energy taxes next year. It's not going to stop this year it will be a continued process, and it has to be our ability to educate them of the merits of the industry and what we do today and the jobs that we create.

Finally, I might add that in my 30 years experience in the industry, XTO and several of its peer companies are working together on federal issues that we never have before. Several of the peer companies have governmental affairs programs for a long time, but our efforts have always tended to be individual for each company and hoping that the cumulative effect would be enough.

Like other industries, we are doing a better job now, I think, of pooling our resources and sharing information like we never have before. So time will tell whether a united voice is heard in Washington, but the early indications that we are seeing, our efforts are not being wasted.

So we are very excited about what we see going on and the changes that we feel as an industry we're going to help manipulate, help change the attitude and educate the members of Congress. So they will see the benefit of the energy sector in the U.S. economy today. So it's kind of an exciting time. We continue to work on it daily. And we'll know more come our next conference call on what's going to happen.

With that, I'll turn it over to Keith on the operations review.

Keith Hutton

Ours was a good quarter both in production up 6% quarter-to-quarter, 32% year-over-year, and operating expenses being down 10% quarter-to-quarter and we are seeing our capital fall as we anticipated to about a 30% drop from the beginning of the year, so all things are working. We had promised that we would have operating expenses below $1 in Mcfe by the second quarter, we're at $0.94. Our guidance is that it basically stays kind of that same range going forward.

If you look at where our production runs we're up, it was mainly driven by Midcontinent and Barnett in the second quarter. If we just take a little look at U.S. gas production for a moment, we from the very beginning have said you would not see U.S. gas production drop until May. Looking at the EA 914, you're down about half a B a day from April to May, which is what we anticipated.

If you were to maintain that same fall for the next seven months of the year, you could potentially be down four Bs a day in U.S. natural gas productions. We'll wait to see but that's not an unreasonable number. If we look at EA 914 and break it down to onshore only, we've actually been down five in the last seven months and we're off 1.7B a day just in U.S. gas production onshore.

What's made the difference is onshore has been coming back on because of the hurricanes and is up 1.1B today and that's the real difference in what you're seeing. So I think you are seeing the decline that we've all talked about with U.S. natural gas recount dropping from 1600 to 675, and you will continue to see that, which should set you up for rebound in natural gas prices going forward.

If you're over supplied 3 or 4Bs a day that would indicate you should be balanced by the end of the year. Obviously, there's a lot of the year left to go. We do have the next 90 days will be very interesting as storage is relatively full at this point in comparison in history, and you may have some gas on gas competition as you get into the September and October timeframe. But I think we are setup as we've all talked about for a rebound in natural gas prices in '10.

If we look at XTO's production and where our volumes were during the quarter, Eastern region first based on trend, we were up 16% year-over-year, up 1% quarter-to-quarter. That had us up about 5% total for the year. Our volume estimates were 5 to 7%. You can see our rig count has dropped from a peak of 27 in the last quarter of last year to 17 today. We anticipate holding it at 17 and probably will get another 2% or 3% growth out it and maybe at the 7% to 8% growth for the year even if they drop recount from 27 to 17.

One thing I would point out and all these people are talking about different plays that are coming online I wouldn't lose focus on our Freestone trend. We are drilling Cotton Valley Lime horizontals. We just recently brought on another well at 8 million a day. It should be a 6Bcf or so well. It costs around $5.5 million to drill. So finding costs in the dollar range and we have about another 10 or 12 of those to drill going forward, which should make it fairly easy for us to maintain Freestone's production, if not grow with a lot less [recount].

If we flip from Freestone then to the Eastern region side Sabine uplift in Cotton Valley, Haynesville Shale, we currently have four returning. We just put our fourth one on. We anticipate picking up a fifth rig in the next month. It should end up drilling 27or 28 Haynesville Shale wells, our original estimates were 15 to 20 so that's part of the increase in capital that you see in our capital budget is focused to Haynesville Shale.

We brought two wells on during the quarter with average first month sales rates in the range of 6.5 million to 7 million a day on the Texas side. And we currently have a well, another New Horizons well that's on line at 10 million a day at 6,000 pounds flowing tipping pressure. I think that's probably going to be the best well we drilled so far.

So Haynesville we are getting better. We've drilled a couple of wells in 35 days. I think our average time to drill those wells was 40 to 45 at the moment. We think our wells range anywhere from 5 to 7Bcf per well, so good economics. That's the reason we're picking up another rig. Currently all of our wells that have been completed are in Texas. We do have two wells down in Louisiana, which we hope to bring on during this quarter, and we're beginning to drill in the Shelby Nacogdoches area of Texas as well.

If we flip from that to Barnett Shale, we had actually dropped from 13 rigs last quarter to 10 this quarter, that's where we'll stop. We'll hold 10 rigs for the rest of the year at the Barnett Shale as well. If you look at our average wells, we're still making wells that come in at 4 to 5 million a day, and our costs are now around $2.4 million to drill those wells.

They are 3Bcf plus type wells because they are all in the core in the better areas. That's where all our rigs are. So again finding costs on the Barnett I know there has been some chatter that Barnett does not have to find the course or the economies of some of these other plays. We do not believe that. Again our production growth in Barnett was up 5% quarter-to-quarter.

Midcontinent region where some of our exciting things are going on, we have Woodford Shale, Fayetteville Shale and Bakken Shale in the Midcontinent region. If we first look at Woodford Shale, we still have 3 rigs drilling. We had set an exit rate of 70 million to 80 million a day by the end of the year. We're currently at 75 million a day, pumping 80 million a day.

The reason for that is our wells are actually much better than we anticipated going into the year. We seem to be making 4 million a day or better IP wells on almost every well. In this quarter we had a couple wells that were 6 million a day, and we have a couple of wells going right now that are in that same range.

Woodford tends to keep getting better as we figure out how to drill them. We do have 3D seismic. We know how to frac them now and our drilling times are coming down to sub 40 days per well. Costs are in the $4.5 million range, which means your finding costs is sub $1.50 at the moment on these better wells. I think Woodford will continue to get better as we understand.

If we look at Fayetteville, Fayetteville went from 60 million a day last quarter to 85 million a day. At the end of this quarter, we still were on target to exit at 120 million a day. Our drill time in Fayetteville is now sub 20 days per rig per well, more like 18 days per well. We're still running six rigs. Our costs are down closer to $2.5 million to $2.7 million for those wells and yes, our EURs look to be going up like everybody else's.

Now we don't change those from quarter-to-quarter. We'll update you at the end of the year once we get more data on those wells, but we have a number of wells now that are in the 4 million to 4.5 million a day start rate. As we get most of our infrastructure in place, you guys will be able to see that if you go out and look at public data. But our wells are matching up to what you're seeing from other operators as well.

The rest of Midcontinent now to Bakken Shale, we brought in 3 Three Fork Spanish wells during the quarter, two of those were on our super pad that we talked about last quarter at 1,500 barrel a day or better on a Boe basis and we brought one well that is just north of the super pad on at 2,400 barrels a day, which matches our best Spanish well drilled to date, the Voucher.

So what we're seeing in Three Fork Spanish is in a pretty extensive area where it looks actually to be better than the Middle Bakken is. We are getting ready to drill Three Fork Spanish wells that are actually underneath the Middle Bakken wells we already have on production to see if there are separate reservoirs.

And if that means you can actually drill many more wells than you would have anticipation because you can drill both Three Forks Spanish and Middle Bakken wells in the same spacing units. I believe personally that that's going to happen in a large percentage of the area as we have Middle Bakken wells that are close to these Three Fork Spanish wells that have been on production for quite a while and are nowhere near as good of wells as these are.

What you're looking at here is cost that are in the $4.5 million range and wells that are in the 400,000 to 600,000 Mboe range. So very good finding costs. In fact currently at $70 oil these kinds of wells are 80% rate of return top numbers.

Marcellus Shale, I wish I had some wells to tell you about on IPs. We do not. We do have three horizontals down, two of them are completed, but we're waiting on a pipeline. And I would rather wait and tell you about how good those wells are once we have them on line and know exactly what they'll flow into the pipeline. That should happen during this quarter.

We are bringing a second rig in. It should be in September, late August, early September timeframe and that should allow us to drill enough wells to scattered completely across our acreage position in the Marcellus and understand exactly what we have by the end of the year. Same answer for the Haynesville Shale as well.

Permian, we have picked up a couple of rigs as oil prices going up versus what we run for most of the year. We're drilling in University Block 90, Goldsmith, our two best fields and the highest economics. Again you're looking at wells that are 70% plus rate of returns. In San Juan we do have one rig running drilling Fruitland Cole wells, which are $ 800,000 type wells that make 1 million to 1.5 million a day and make 1.5 to 2Bs, very good economics.

With that, I will wrap it up and turn it over to Mr. Simpson.

Bob Simpson

You can see the company is in really good shape, given all the cylinders hitting together again. Last year we built a bridge that financially that actually we think will extend over the downturn and at the same time, as we go through that downturn, the company is enjoying record cash flow. And so the combination of all the strategies coming together, the excellent performance, the operating group, combined with the financial strategy of keeping relatively hedged.

And for this year we had extra hedging. We're closer to 75% hedged instead of 1/2 to 2/3. All that working together, we're looking at record cash flow. Now if you look at the concept where the investor, in terms of investment, as we all know, that's all well and good but what are you going to do for me now is the attitude of incremental investment, which it should be.

If you look at the future, say well is this an anomalous financial prosperity that won't continue or should we look forward to continuing success? If you look at next year in terms of cash flow, we are approaching this year's cash flow given the current strip already.

Now what we will, if you look at the hedge book, we're about 40% hedged at a little over $11 in Mcfe. A good deal of that is explained by hedges done last year coupled with a good fraction of that hedging being oil, which has a higher BTU content or higher value per BTU at six to one. And so that's a very excellent base on which to build. And given where the strip is today, we're already seeing numbers that would suggest close to $2 billion free cash flow again next year.

The company is continuing its financial discipline. Last year was a record year dollar expenditure as far as incremental growth to the company in terms of the percentage. We've done it several times in the past so it was a manageable rate of growth for our organization. Financially we've digested it. We cashed in on hedges early. We issued equity last year as we did it and then we put hedges in place that protected the returns for the first couple of years on those acquisitions. So with all that in place, we paid for almost 70% already of that activity last year is paid for.

So we now turn to what we're doing this year. We're projecting year-end debt at around $2.5 billion. We did increase the budget slightly this quarter. That was a reflection of a couple of things, primarily driven by non-op activity was running above forecast, so we adjusted those dollars for you and went ahead and included those in the budget.

And our activity otherwise is up slightly given our growing confidence in the recovery in the economy. We're not going to take activity down quite as low as we projected say 90 days ago. That's a slight adjustment upward in our activity, but with that came an adjustment of the growth this year of 20% up from 16%, so you're going to get something for the money in terms of volume and value.

And of that, one thing that I think is very significant, about half of that 20% or about 10% of the growth is drill bit and so we, for a company this size to demonstrate that with these kinds of dollars we can have a 10% drill bit growth and still have a couple of billion plus of free cash flow I think is a very strong financial machine that obviously is going to create value and you can see it. It takes about 1/3 of our cash flow to stay flat in terms of production and reserves. So we have 2/3 to grow with and so it's important what cash flow is and we're aware of that.

If you look at the free cash flow machine, that's $3 or $4 a share on the stock that trades for around a little over $40, and so you're not only getting that kind of growth, but you have a free cash flow machine that has almost a double-digit yield beyond the volume growth and so the two together result in an exceptional value creation machine.

And our job is to continue that and keep that machine going and we're already looking at 2010 and securing that those kind of dynamics going into that year. And so I think the feeling that this tremendous prosperity is artificial created by fortuitous hedges from a bygone era is wrong.

With our volume growth and the recovery we're seeing and the commodities markets that it's already been achieved, we think this cash flow machine continues at numbers similar to where we are now. And that's the surprise I think for the investment community as that unfolds.

Somewhere around $7 gas strip, our cash flow would be virtually unchanged next year. So it doesn't take that much more from around 620 where it is today to get a full recovery and a full cash flow sustaining this record cash flow we're now enjoying. So that's a possibility. And on the other side, the current strip, it's already over 90% of this year's cash flow projection. So we can see the future remaining bright for our company.

On the financial discipline, I think it's important to keep it in terms of value creation and I think it's more important than it would have been in a normal year, so you're seeing us continue that. Acquisitions are very modest. Leasehold is modest. Even with the slight budget increase we're talking about, we're not changing our debt assumption for year-end at $10.5 billion as the goal.

And what we'll do is if that slight uptick in the budget, we'll simply just take out of cash flow and not borrow that. And so in essence it's view it as a [inaudible] that we're going to enjoy through the drill bit. That's the way we'll approach it financially.

So the discipline is strong here. It's more important I think than normal that we keep it. We're recovering on our stock price. We're improving the strength and the wisdom of last year's activity and also verifying that the model didn't change. This is an acquire and exploit company. It just now embraced the shales which is, as the world will see, is an acquire and exploit opportunity for a company like XTO if employed correctly.

And actually it's a reinvention of the industry a little bit. And those who don't get on the cutting edge are going to be somewhat left behind. And I think you'll see the vision of XTO starting the last few years and particularly aggressively last year was to be a leader in the unconventional plays, as we've always been a leader in value creation and a leader in the [gas] plays and the [cold seam] as they came along.

And so that's our job is to continue to stay on the cutting edge and I think we've done that well. The fear of gas being set by the very best prospects of the industry, and that would be to choose your play whether it's Marcellus or Woodford or Barnett or Haynesville, is not correct. But you can't take the very best economics of almost a 60 Bcf a day industry and say that will set the economics for the whole play.

The reason is you can't get enough volumes out of any one of those areas because the infrastructure is not there. And the decline curve that's in place for the industry is too fierce. If you look at onshore production, it is off 3% since the peak. And remember, during this particular period we were working off the inventory of drilled wells that came out of that record activity.

So that deceleration in onshore production will accelerate. We got 3% in the last six months against as we worked off the inventory, which is in our estimations, 90 to 120 days from a record drilling level. And so we think that will accelerate so that by the fourth quarter onshore probably we'll be off at a 10% rate year-over-year and again somewhat mitigated a couple of points by bringing onshore back from the hurricane deficit of last year, but that's over.

That event's occurred and so that won't continue. And so you'll have net shrinkage now and that will be the savior of all of us. And also the economy will be recovering some. And so we think that full cycle economics, it does take a $7 or $8 gas price. I think oil is going to be sort of an $80 to $100 number in the recovery, and so gas being $7 or $8 will still be a bargain.

And if you look at it full cycle, the other industries the service industries need a rate of return, too, so these low service costs will not be sustainable worldwide indefinitely. We'll enjoy them now, we [hope hedged] cash flow will take advantage of it.

We've done this before, but we will maximize service costs at some point in the year and they will start to recover as well, probably mid next year would be my guess. They'll lag some, they always do. The upturn will come first with commodity and for the producer, and so I've always enjoyed being the producer instead of the service guy, and I still do. And I think we have an edge.

But if you look at the recovery, it's coming. The seeds are in place and so we'll all enjoy that and the equities will enjoy that as well. At some point, the market trades it, there's a record storage in natural gas futures. I saw it was a trap being built, I believe. It's going to be sprung at some point. It will probably happen very quickly and will come off data points that we can all see. And it probably has to do with declining production will be the trigger.

We've got to work through record storage, but relative to aggregate demand it's not that big a deal. I always say storage is something you fill, we're going to fill it, we'll find out what the limits are this fall. There will be some curtailment in the fields, line pressures and so forth, so it won't be as big a bill as the theoretical model would give you because maximum production will not be enjoyed.

One of the things we've done in our guidance is built this cook in a little of that, if you study it, a little curtailment in the last six months as a company, and that will come to a focus in October. You'll see that nationwide to a degree and so that'll keep storage from getting as big as the model might suggest, although it will full whatever that is.

And we can debate what that is, no one knows for sure, whether it's 3.5, 3.6, 3.8, I don't believe its 4, personally. I think you might put some gas in there that you don't get back. It might benefit some local producers around some of these places, but I don't believe it goes to 4, but we'll test what that theoretical limit is.

With that, the company's in great shape, we'll keep our discipline. The acquisition market, I really haven't seen a return of it, in aggregate and specifically for this company, we're not particularly interested because we have so much opportunity that we have onboard already. There's no need to stretch the point and strain the company for more opportunities when they're so bountiful within.

We'll continue to do mole tones, our small additions for drill sites, but we don't need a generic acquisition, we don't need a franchise acquisition and we certainly don't need an acquisition that would involve our equity, which I submit continues to be undervalued and not a tool. It's a great value width at the moment in terms of issuing it. So we'll keep that discipline for you and look forward to great quarters as we go through the rest of this year.

With that, we'll throw it open for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from David Heikkinen – Tudor Pickering & Holt.

David Heikkinen – Tudor Pickering & Holt

Bob, just as you think about guidance including curtailments, how much of that is really voluntary and how much of that is just pipeline pressures coming up and involuntary in the industry?

Bob Simpson

For us, we're projecting involuntary. Unless we have a basis blowout somewhere in like the Rockies, we don't practice in gas because of the dB of the unit. At $3 gas, if you shut it in, you move it to the end of the line and actually present value basis, you didn't help yourself. And so we don't practice manipulation of the volumes in general, unless it's just silly.

David Heikkinen – Tudor Pickering & Holt

Keith, as you think about the tie between increasing CapEx this year and increasing production guidance this year, kind of a rough dollars-in dollars-out balance there, how do you think about the increase in Haynesville drilling or other areas, Bakken and kind of Permian from a dollars-in dollar-out balance as far as how that impacts production, both 2009 guidance and then in 2010.

Keith Hutton

David, I'm not sure what you're asking, dollars-in dollars-out –

David Heikkinen – Tudor Pickering & Holt

It's basically you look at your CapEx up, you production guidance went up associated with that, is that just a direct drive or are you seeing better efficiency for where you're investing the capital now or is it –

Keith Hutton

You're seeing all of it, you're seeing better efficiency, your wells are better than you thought, and so it's just, what you're trying to do, really, by upping your guidance is to make sure you set yourself up for '10 because you're actually seeing wells that are better in some places than you might have thought, so you don't want to slowdown drilling in those particular areas, you want to spread it out so that you're setup to run as gas prices rebound.

So I think that's the real game here. We're pushing more capital towards Haynesville we're pushing more toward Marcellus. Like Bob said, we've got some non-op guys drilling more wells than we would've anticipated they were drilling. Hey, look, it happens to be in Haynesville and Fayetteville and those are great places economically. So all of it's really you're spending the money wisely in the right places and you're setting yourself up for future growth.

Bob Simpson

Yes, it's not a type of situation where you would go non-consent. There is a decent enough rate of return, even at lower gas prices to justify the expenditure so we're not going to go non-consent. The other thing, obviously, we've adjusted our oil drilling up a little bit because its recovered year hedged at 96 and have a go at it, and we're anticipating stepping all volumes up next year.

We've said publicly that the 70,000 barrels a day is about 95% hedged and, of course, the 70,000 barrels a day alone is above current rates, so we're anticipating growth and we're budgeting growth and so an element of it is not anticipating recovery. Part of the step-up in budget is to take advantage of the oil recovery that's happened.

David Heikkinen – Tudor Pickering & Holt

Yes, so don't have the question earlier of 2009 production guidance isn't up as much as you would expect with the CapEx uptick and you explained pretty well that it's really setting up 2010 numbers and that carries through into next year as much as what's going on this year. Thanks.

Operator

Our next question comes from Subhash Chandra – Jefferies.

Subhash Chandra – Jefferies

Keith, curious in the Haynesville, I guess a couple of part question here, the second New Horizons well, the ten a day, what sort of time period was that? And secondly, what are the assumptions behind that I think the 60 or 70 a day exit Haynesville rate you have in the press release?

Keith Hutton

Well, basically, it's the second well had been up two weeks in New Horizon, it's actually the third well in that lease and so for it to still be making 10 million a day at [6,000 pounds slight case in pressure] means this well is stronger than the ones we drilled before.

If we look at what our exit rate, 60 to 70, it's really hoping we'll get 14 or 15 wells completed by year-end, even though we'll drill 27. So again, those other 13 or 14 wells will be rolling into first quarter of next year. So again, those other 13 or 14 wells will be rolling into first quarter of next year.

Subhash Chandra - Jeffries

And the 14 to 15 or even the 20 and change, you think it is primarily east Texas that's looking at sort of the rig disposition at the moment?

Keith Hutton

Yes. But you should have, say, four or five wells on Louisiana as well. And so there'll be a wild card. We've got some acreage that's real close to some of these good wells that everybody's talking about in Louisiana. And so we've got a chance to beat that 60 or 70 should some those wells be as big as what some of these other guys are kicking out.

Subhash Chandra - Jeffries

Have you thought about how much potential relatively you might have in Louisiana? I guess the picture in the presentation does a good job of showing the relevant acreage, but any way to sort of conceive of locations at this point?

Keith Hutton

No, we haven't really talked about it, Subhash. I'd rather flush that out as we get toward the end of the year.

Subhash Chandra - Jeffries

Secondly, Bakken, any thoughts here on Mercer County, I think you've drilled there a little bit, and then Elm Coulee trying to do the Three Fork Spanish there. And, finally, I think you've really grown the Heddington oil volumes since the acquisition, maybe some commentary on if and how much and what the outlook looks like.

Keith Hutton

Well, first let's do Three Forks and Elm Coulee. Some other people have been testing Three Forks around Elm Coulee. Their results don't look all that great. We might test one late this year. But most of our focus is actually over in North Dakota because we've got acreage to hold and those wells have been so good. So you may end up looking at Three Forks and Elm Coulee sometime next year as an upside.

Mercer County, not a lot of comments on that at the moment. And if we look at your question on Heddington, we thought we could probably double the production on Heddington from 10,000 barrels day net equivalent to 20. As good as these wells have been, we're actually growing production with three rigs, Heddington couldn't grow it with four. That just points to how phenomenal your wells have been in comparison. And I think that there's a chance you can triple production out of Heddington now instead of double it.

And most of that is going to be focused because when we bought Heddington, we knew we could drill infields in Montana and Elm Coulee, we knew we'd have pretty good Middle Bakken wells in Ness and our wild card was Three Forks, and it looks to be better than what we ever thought it would be, over a large (aerial) extent. So I really think your Bakken acquisition's going to look phenomenal over the next couple of years.

Operator

Our next question comes from David Tameron – Wells Fargo.

David Tameron – Wells Fargo

Bob, if I think about the big picture, I hear you on the [EI 914] and I don't disagree with what you're saying, but we hear [Nurcells, Chesapeake, Devon], this morning everybody seems to be coming out raising production bend, or at list reiterating for the year, if not raising. People are throwing more CapEx into the system, yet everybody's still talking about voluntary curtailments. So I'm just trying to reconcile. It seems there's a little bit of disconnect with what's being said on the public market versus what everybody expects to happen. Can you talk a little bit about that?

Bob Simpson

I think if you look at the industry as a whole, the ones you're hearing from are the publicly held guys who, in general, are the ones that either have growth or can talk about growth. There's a lot of the industry, including the majors and the privates that we don't listen to. And so the picture is not balanced we think. And so the rest of the world is going to be the one that pulls the aggregate production down. The growers are the ones who are listening to, Lou's go some statistics that we've got from the first quarter too. Lou, why don't you go over those?

Louis Baldwin

I just put something in front of Bob that compares second quarter '08, second quarter '09 and yes there are some big guys that are up. Certainly Southwest and [Nurcells] have increased production there, although with us a lot of that is Burgess Production. But if you look at some of the bigger guys, Exxon, Chevron, Marathon, there's some big decreases in there also.

So even among the public guys you are having a bifurcation of people and candidates choosing to shut-in some gas. You have a lot of guys who just don't structurally have a plan to grow production and then that compounds with all of the private guys that Bob is talking about that are cash flow drillers that will be coming off.

I think one thing we believe is that the cycle may be a little shorter than it was in 2001, 2002, where you had four years of down production just because the shales offer a lot of inventory for drilling, you don't have to regenerate your prospects. But we still think that production will be down for a multi-year period until things start to come back.

David Tameron - Wells Fargo

So the basics position is private majors are turning over which offsets the growth coming from the independents?

Bob Simpson

Yes, so the things that we listen to are the ones that, to give you a little different picture. The privates, I think you can look at the aggregate rate count and probably get the flavor of the whole thing. You drop 1,000 rigs, that's going to have an impact and a lot of that is stealth. I mean it's not guys that you talk to or that are publicly held. Private guys, not drilling, I mean its $3 or $4 gas he's not about to be doing anything. And so they own 40% of the supply and so that's off radar.

David Tameron - Wells Fargo

One more question for whoever wants to take it my favorite question of the quarter is over or under on rigs a year from now that you know, 9, 950 or let's say 950, would you take the under or over as far as natural gas rigs in the U.S.?

Bob Simpson

Under.

Operator

Our next question comes from Tom Gardner – Simmons & Company.

Tom Gardner - Simmons & Company

Keith, I appreciate your comments on gas supply and I wanted to get your thoughts on the overall impact of these drilling efficiency gains being reported across the industry?

Keith Hutton

You know, there not unusual, Tom. But look, we dropped some of our less efficient rigs in industry [inaudible]. But those gains are not enough to make up for near what your rig count drop was. So you might see people increasing 10% efficiency across the board, which would be another 60, 70 rigs or something difference. But it's not going to be like your efficiencies have gone up 25% or something. It's not that high.

Tom Gardner - Simmons & Company

Do your estimates sort of bake some of that in?

Keith Hutton

Yes. I mean if you look at Texas production itself, which is going to be Barnett, South Texas, West Texas, most of the production decline in the U.S. has come out of Texas where all those rigs were. And again a lot of those guys were privates you don't hear about and Texas itself saw 1.7Bs a day or something since November, so it's been most of the U.S. production drop.

Tom Gardner - Simmons & Company

Following up on Bob's comments on full cycle economics and thinking about how deflation is moving around those full cycle economics. How much is the average cost to drill a well deflated in your view, and how much of that does industry give back in a seven day dollar gas price environment?

Bob Simpson

We're seeing drilling costs are off 30% at the moment, and then there will be a lag. Actually, our experience is the cost actually bottom after the price starts recovering. And as far as full cycle return, I would guess, and Keith you can speak to your feelings of it, you'll recover at least half of that, maybe 2/3. Probably won't go to the all time highs because I don't think gas is going to reflect, part of that drilling psychology was set by double-digit gas prices, or over $10 gas prices. I don't think that's going to happen.

The positive thing that's going on is that, for the country and for our industry, is that for the first time in my career, we can say with confidence that we're going to have a bountiful supply of natural gas in America, and the first time that happened. Our industry can rely on it. You'll have more manufacturing because of it.

We're going to have a growing market because of it because people will in time become sort of relying on that. And so many jobs and manufacturing activity won't be going offshore as would have gone. And maybe we'll even bring some back, for example, fertilizer at times have been driven away. And I think that that's going to be more secure here.

And the growth of farming for the world is very bright and that's a great place to be secure. And I think Washington over time will be friendlier to natural gas because of it, because there's [the fence] of the reality that we can supply this country with natural gas. It's our most visible secure supply. If you look at going green, it's a nice concept. But we're going to have to learn to accept that natural gas is part of green because it's you're only realistic way of natural gas security, of energy security.

You look at the numbers for wind and solar and they're less than 1% of supply. And so, yes, you can double them and triple them and still not do anything particularly meaningful. Natural gas, you can do something. And so I think the future for natural gas is understated and underappreciated at the moment, because we're all captured with the thought of we're going to drill ourselves into [blot] because of them, but I think we've missed a little bit of the story or quite a bit of the story over time as the demand is going to return and grow because it's reliable now and we're going to supply it.

And then Congress will be friendly toward natural gas over time, and I believe that. There may be moments when we lose sight of that. But I think the reality of the great security of that resource will prevail and calm our minds and give us a more secure supply and a more secure feeling about this industry.

If you look at it in terms of cost, $7 or $8 gas is still below $50 oil equivalent. And most of us believe it falls closer to $150 in the next five years as an average. And so it will continue to be a bargain. We're approaching probably half price. And all of that bodes well, I think, for this industry. And so I'm pretty confident that the full cycle for natural gas is $7 or $8. But I don't think you'll have the spikes up to $15 anymore, and that actually in the long-term is probably healthier.

Operator

Your next question comes from Scott Hanold – RBC Capital Markets.

Scott Hanold – RBC Capital Markets

Just to talk a little bit about production guidance and the involuntary curtailment expectations. Can you kind of give us a sense what's baked into guidance for that type of curtailment? And are you seeing it already, because if you kind of look at your average second quarter volumes and your expectations in the back half of the year, I'm having difficulty kind of getting to the answer. It looks like your guidance is a bit conservative.

Keith Hutton

I think we're just basically saying look, we know we'll get pressured off, and the way that works, guys, is they just let pipeline pressure slow it up. And it's not that you knock a bunch of wells completely off. You knock of 20 Mcf a day a well over 1,000 wells or something. It's a very slight effect. We've seen it before.

That's the reason we estimate it that way. Most of that down production is really associated with. We think we're going to see that happen. And hopefully that doesn't happen to us as bad as it does to others when we end up [eating] that guidance. But that's what we're guiding toward.

Scott Hanold – RBC Capital Markets

Do you have a sense on what that is or what do you have in guidance for that?

Keith Hutton

It's basically the difference is kind of what we're playing with.

Scott Hanold – RBC Capital Markets

Is there a particular area you all sense is going to get hit more than others this year?

Keith Hutton

No. It's pretty hard to estimate that. I would guess the Rockies gets hit fairly hard. But that's an experience factor from previous times we've gone through this. But that doesn't mean they won't do it everywhere as they build storage. It's going to be site specific to particular pipes and how full the storage is and close to them.

Scott Hanold – RBC Capital Markets

Then maybe let me ask it this way. Where have you seen it the most in your assets in the past?

Keith Hutton

Rockies.

Scott Hanold – RBC Capital Markets

When I look at the performance you had in the Freestone trend, I mean, it looks pretty tremendous where you've kind of kept the rig count flat or actually down over the last six months, yet production kind of keeps climbing. Can you talk about what's really driving that? And the Cotton Valley Lime, what implication does that have to the growth outlook for the Freestone?

Keith Hutton

Well, if you just look at what's happened. We brought on our last infrastructure and plant. We've started it up in the last month of the second quarter, which helped us punch production up even as rig counts were going down. So we now have three plants that are capable of treating 330 million a day a piece and a single plant that's a 65 million a day plant. So Freestone is now set up to produce 1.1Bs a day plus. We don't need to build a bunch of infrastructure out.

So that is part of the reason we were able to hold it with less rigs. Now I do think that what you're going to see as we draw more and more of these horizontals, is that it takes less and less rigs to grow Freestone, which is a good answer for us. And we'll be spending capital off to a bunch of these new plays.

Scott Hanold – RBC Capital Markets

Last question, in South Texas kind of in that Washburn area, I think it's La Salle County. Do you have any prospectivity there for the Eagle Ford? Have you looked at that yet?

Keith Hutton

We have. We're watching it real close. We do have some acreage in there. I'm not really ready to talk about it. We have done some re-completions in some other wells and they look fine. So, we'll probably bounce into that play eventually and start talking about it, but not at this time.

Operator

Your next question comes from Nicholas Pope – Dahlman Rose.

Nicholas Pope - Dahlman Rose

I had a quick question with regards to the commodities during the quarter. Do you all have – can you all breakout what I guess the realized pricings was for gas, oil, NGLs, excluding the impact of kind of derivative or hedging?

Louis Baldwin

I can. Maybe versus kind of going through my notes, I'll just give you a call, Nick, on that and take you through that, but we have those numbers available. And we do have an improvement with the basis improvement for the year. Our realization is now exclusive of hedging. But I'll take you through that. And I'll be happy to give you a call later this afternoon.

Operator

Your next question comes from Phil Dodge – Tuohy Brothers.

Phil Dodge – Tuohy Brothers

Two questions, first, can you tell us what level of spending is embedded in your 2010 guidance of internal growth of 10% in production?

Bob Simpson

Actually, we haven't set the number because first of all, we would like to get service costs at year-end and to look at them, but it's not materially different than the current level expending.

Phil Dodge – Tuohy Brothers

Presumably, activity would be up more because of decline of service costs in the same level of dollar spending.

Bob Simpson

Yes, but again, your base is larger so you'll need a little larger activity level for the compounding effect.

Phil Dodge – Tuohy Brothers

Other one is, whether you experience any transportation problems with the Fayetteville shale production.

Keith Hutton

Not yet. Obviously, I know what you're talking about as Boardwalk's got to take their line down to do some testing and fix some problems they have. We could see a little curtailment in the third quarter for that because we are in Southwestern's wells and I know that they were talking about getting curtailed. Our volume is not high enough at the moment that I think we'll get hit real bad. We're going to be able to offload our volume to other pipes in a particular area.

Phil Dodge – Tuohy Brothers

I was just going to ask you whether your alternatives to Fayetteville absorb that shortfall.

Keith Hutton

Yes, they should, but that doesn't mean our non-op won't get hurt a little bit.

Operator

Our next question comes from Kent Green – Boston American Asset Management.

Kent Green - Boston American Asset Management

My question pertains to what kind of efficiencies that you're getting versus pricing in oil service and LOE costs. And then whether you would have achieved most of that or whether you've got rigs that are going to roll of under contract. And then what do you see going forward into next year? Where are the areas under your guidance where you think you could possibly see lower costs?

Keith Hutton

Operating expense-wise, I think, in general, most of your cost has occurred. You're probably toward the bottom of the cycle from an operating expense standpoint. Pulling units have actually been cut in half on day rate over the last year, and they doubled the previous years, so we we're kind of back to the '07, '06 rates. I don't suspect they'll drop those to more and people will start picking those back up, because work-overs obviously are the easier and better economics answer than drilling.

I think drilling costs we in particular have a number of rigs that we'll roll off towards the back half of this year. We only have six rigs that are anything longer in a year contract, and so we're setup to experience any drop you see in drilling costs.

What I'd tell you is, you're probably close to the bottom, but if you go back and look at '01, '02 timeframe, actually, drilling costs, as Bob said, kept falling even as process rebounded. People didn't pick up rigs as fast as you might have anticipated. I actually think you're setup for exactly the same game, personally, even with the shales I think you're set up for it. And so, I suspect you've got some downward pressure still on rigs. And, obviously, as ours come off of contract here in the back half of the year, that'll help us on our overall cost on drilling.

Pipes are the one thing that hasn't come back as much as it should have. At this point, it doubled in the first six months of last year, and it's off probably 50%. So, it has another 50% to pull back and it should. And so, that might be another 5% reduction in drill well costs, if you look at it kind of on average. But in general, I'd say you're getting close to the bottom.

Kent Green - Boston American Asset Management

What about the total efficiencies versus lower cost question? Efficiencies are ongoing here. You've even mentioned a couple of the Haynesville wells coming down in drilling time. And, of course, almost all of these new shales will come down probably at drilling time. What is an estimate of say, annual efficiency, just from getting more experience in these new fields?

Keith Hutton

I think at best you'd do 10%, honestly, on [inaudible]. You've got new participants coming in that don't do very well for a while, and you've got the guys who are drilling the most wells. There's the guys that make up the most efficiency. Your efficiencies are really driven by crews on rigs. There's a bunch of good pipe out there, but you've got to have good crews.

So, the issue you run into is, as you start to pick up new rigs, your crews may not be experienced and your efficiency will actually go the opposite direction on you. It happened in the last couple of cycles. You got real efficient at the very bottom, and then your efficiency got worse as you started picking up rigs.

The longer we stay down in rig count, the less those crews that were on those 1,600 rigs are going to want to work in the oil and gas industry. They're gone. And so, the problem you get into is now you get the green guy you hired out of Wal-Mart, and basically they start spreading out the experienced guys to rigs, and your efficiency starts getting worse. We've seen it in every one of these cycles. So, I think people think we're going to be a lot more efficient, but if we start picking up rigs we're actually going to lose that efficiency with the new rigs.

Operator

Our next question comes from Subhash Chandra – Jefferies.

Subhash Chandra – Jefferies

One last basin here, I was curious about the Woodford. We've seen a variety of operators definitely slowdown their, temper their growth expectations. And by your math and our math, it's just not as robust on the economic and it's represented a big chunk of the growth trend.

So, couple of questions here. First is, you talked about the exit rate where you are today. Are you raising the growth profile for the Woodford through the balance of the year? And, then, secondly, is this sort of that quest to try to drive the economics down and get into the efficient phase of drilling? And, if it is, sort of when do you envision that happening and how much time do you give it, if for instance, gas prices don't recover?

Keith Hutton

Subhash, here's a look at it. I think you're looking at these kind of wells that come in at 4 million to 6 million a day, first month, are in the 4 to 5 Bcf range, and it costs $4.5 million to drill them. So, economics-wise, they're much better than what people are focusing on. It's going to be competitive in almost any shale play, and so I think there's still a misnomer about Woodford. As the industry's getting better, I think those numbers will actually look better with time.

So, we don't really think Woodford's all that different than some of the others. You have high NRIs there. They're 80% to 85%, so you don't have as high royalties as a lot of places. With Midcontinent Express and Gulf Crossing coming on Midcontinent prices are going to be a lot better, because you're carrying it over to Perryville. So, pricing is getting better, costs are going down, and wells are getting better. So, I wouldn't discount Woodford that much.

Now look, the reason our volume guidance should go up is we haven't picked up any rigs, we've actually dropped rigs our wells are just a lot better. So, we didn't anticipate hitting 4 million and 6 million a day, wells left and right. So, I think the answer is sure your volume's going to go up. I would guess it has to be 90 million plus as an exit now. But, again, that's with actually a decreased rig count from what we started off in the year, so that just points to the efficiencies that we're seeing in.

Operator

This concludes the question and answer session. I would now like to turn the call back over to Louis Baldwin for closing remarks.

Louis Baldwin

Well, thank you very much for listening in. Obviously, our quarter we're delighted with, and most importantly as Bob really did a good job of talking about, is that this prosperity is not just one year because of the hedges. It really relates to the properties that we bought, the production increases that we're seeing, and through sustained hedging through the end of 2010. And we expect a record year this year, and another great year in 2010. Thank you very much.

Bob Simpson

Thanks everybody.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.

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