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Unit Corp. (NYSE:UNT)

Q1 2009 Earnings Call

May 05, 2009 11:00 AM ET

Executives

Larry D. Pinkston - President, Chief Executive Officer, Chief Operating Officer and Director

Brad Guidry - Senior Vice President, Exploration, Unit Petroleum Company

David T. Merrill - Chief Financial Officer and Treasurer

Analysts

Robert Christensen, Jr. - Buckingham Research

Pierre Conner - Capital One Southcoast

Marshall Adkins - Raymond James

George Gasper - Robert Baird

Operator

This conference call contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. All statements, other than statements of historical facts included in the call that address activities, events or developments that the company expects or anticipates will or may occur in the future are forward-looking statements.

A number of risks and uncertainties could cause actual results to differ materially from these statements, including the impact that current decline and was being drilled with our production and drilling rate utilization, product capabilities of company's wells, future demand for oil and natural gas, future drilling regulations and day rates, projected growth of company's oil and natural gas production, oil and gas reserve information, as well the ability to meet its future reserve replacement goals, anticipated gas gathering and processing rates and throughput volumes, the prospective capabilities of the reserves associated with the company's inventory of future drilling sites, anticipated oil and natural gas prices, the number of wells to be drilled by the company's exploration segment, development, operational, implementation and opportunity risks and other factors described from time to time in the company's publicly available SEC reports.

The company assumes no obligation to update publicly such forward-looking statements, whether as a result of new information, future events or otherwise.

Thank you. Mr. Pinkston, you may begin your conference call.

Larry D. Pinkston

Thank you, Gaston. We want to thank you for calling in this morning and welcome to Unit Corporation's first quarter conference call. With me today are David Merrill, Unit CFO; Brad Guidry our Senior Vice President of Exploration for Unit Petroleum; John Cromling, our EVP of our Contract Drilling Operations; and Bob Parks, President of Superior Pipeline Company, and Mid-Stream Operations.

Need to bear with me this morning, I'm having a sinus infection, but hopefully I'll be able to get through this. I'll spend a few minutes recapping Unit Corporation's first quarter results. I will also provide you with an update of Unit Drilling and our mid-stream operations. Brad Guidry will discuss the details on our E&P operations and David Merrill will discuss key financial facts and figures. We'll take questions after our comments.

We released our first quarter reports to the public this morning. We reported a loss of 147 million. This loss includes a 281 million pre-tax non-cash impairment charge against our oil and natural gas low (ph) cost fuel.

Excluding the impairment, we would have a net income of 27.6 million or $0.59 a share. The majority of the reduction in adjusted net income's between the first quarter of 2009 and the fourth quarter of 2008 was a result of the lower rig utilization and margins for our contract drilling fleet.

We continue to focus in the first quarter of 2009, on increasing capital and operating costs. We are not planning on bringing out any additional new rigs during 2009, other than the one rig in the fourth quarter. That rig is contracted under a three year agreement. We are continuing to minimize order for any other capital commitment for our drilling segment. We are also referring into the second half of the year such of our exploration development drilling. We felt very confident going into the first quarter that the average cost of drilling and completing wells would be much cheaper in the second half of the year than the first.

The lower level of activity has shown up in our balance-sheet, our long-term debt has been reduced by 36 million and stands at 163.5 million at March 31. We believe that our strong balance sheet will enable us the opportunity to look at several E&P and midstream opportunities that may occur during the second half of the year.

In our contract drilling segment, the first quarter was a continuation of the declines that began in the fourth quarter across the energy industry. The slowdown in the industry, rig utilization and our utilization is a result of the substantially lower oil and natural gas prices along with the continued weakness in the credit and equity markets. We averaged 53 rigs operating in the first quarter and we currently have 39 rigs contracted.

Our average day rates during the quarter remain relatively stable during the first quarter decreasing only 4% or $692 a day. Our daily operating margins before elimination of inter-company rig profits was $8200 a day, down 14% from the fourth quarter. The increased cost per day was almost entirely due to the more fixed cost, such as Taxes, insurance et cetera, that does not adjust as each rig is flat (ph). This costs for a more slowly and are reducing but not at the same rate as rig utilization fell during the first quarter.

As I emphasized on our fourth quarter conference call, we are focusing... continuing to focus on controlling our costs. We have over 45 years of experience in the contract drilling industry and we have always been one of the lowest operating cost drilling contractors.

In our midstream segment, financial results for the first quarter were slightly lower than the fourth quarter of 2008. Realized prices for natural gas liquids in the first quarter were comparable to the fourth quarter of 2008, but nevertheless at low levels compared to all of 2008.

Volume together with the process have held up well in the first quarter despite an overall slowdown in the drilling activity, new well connects are so far been equal to the price in early 2008.

During the slowdown, a new construction activity, we are focused on optimizing our existing operations.

With additional focus on reducing field operating cost, we are seeing favorable cost reductions in all categories from chemical costs to round (ph) compression costs. We have also reduced our field employee count by 10% in the first quarter.

With regard to new business development, we are primarily focused upon acquisitions of existing facilities particularly, those possible bolt-on assets adjacent to our current assets. In Appalachia, potential new pipeline construction projects are delayed due to the drilling slowdown but several projects involving traditional existing production are under evaluation.

In our Exploration and Production segment, as I mentioned earlier, we started the year all slow. Costs are coming down both in drilling cost and completion cost. Some of our frac costs are being bid at 30 to 35% lower rates than they were just 30 days ago.

Our oil and natural gas production was down 1% on a per day basis between the fourth quarter and the first quarter. We are still comfortable with our original guidance of 63 to 64 Bcfe for the year. We have four areas that the majority of our E&P budget is directed towards, including the areas of Segno and the Granite Wash. Our analysis shows that these two plays are in a 19 to 20% rate of return at $3 natural gas prices and $35 oil. A unique feature about both plays is the natural gas is very rich with liquids.

We get a 100% of the value of the upgrade in pricing from natural gas liquids. The two other plays are more driven at this stage by science and they will provide growth opportunities in future years.

I now would like to turn the call over to Brad and he can discuss these prospects more in detail.

Brad Guidry

Good morning. We completed 29 wells at the end of the quarter at a 90% success rate and had an additional 16 wells that we're either drilling or completing. The majority of our drilling during the first half of 2009 will be vertical wells that are concentrated in prospects they have either have well commitments or at least exploration.

We are constantly revaluating the drilling economics and will adjust our drilling program either up or down as market conditions dictate. Most of our drilling this year as Larry mentioned will be in two of our legacy plays, the Granite Wash and the Texas Panhandle, Segno Wilcox in the Texas Gulf Coast and then in two of our newer plays are both Shale plays, the Haynesville Shale in East Texas and the Marcellus Shale in Pennsylvania.

In the Granite Wash play, we drilled two vertical gas wells during the first quarter and have a unit rig working continuously in this prospect area. We anticipate we'll drill approximately nine vertical wells and one horizontal well at an approximate net total cost of $18 million for the year.

As I mentioned in the fourth quarter, we completed our first horizontal Granite Wash well back in November of '08. That well has now produced approximately half a Bcf of gas equivalent during the first five months and have current rate of approximately 3.1 million cubic feet a day. We estimate ultimate reserves on this well to be approximately six Bcfe at a completion cost of approximately $6 million, which results in the finding cost of approximately a $1 million dollars per Mcf.

We'll continue to monitor production going forward and will anticipate drilling an increasing number of horizontals in this play once this drilling activity picks back up.

In our Segno prospect in the Texas Gulf Coast, we completed two wells during the first quarter at a 100% success.

In addition to our historical Wilcox sand tests, we have also increased our focus on drilling potential shallow oil plays in both the upper Wilcox and the one (ph) within that prospect area.

One of our 2009 recent oil completions was upper Wilcox sand at approximately 7,000 feet that was completed for a cost of approximately $1.3 million. The well has been flowing since late January on an average rate of approximately 215 barrels of oil per day showing very little decline.

The oil well cogs and the associated higher price for oil makes this play very economic. For 2009, we plan to drill approximately 10 wells in this segment (ph), field area at an approximately cost of $20 million.

In the Marcellus Shale, we have now participated in two vertical wells located in Somerset County, Pennsylvania. The Shale (inaudible) segments in these wells came in as expected and completion work on these two wells should begin mid to late May. In addition, we'll participate in one more vertical well and two horizontal wells during the remainder of 2009 at approximate net cost of about $8 million. Anticipated first gas wells from these wells should occur later this year.

In this Somerset area we own approximately 180,000 gross and 55,000 net acres.

In the Haynesville trend in East Texas we've now drilled five vertical wells in Shelby County. And we have two of the five wells hooked up to gas lines. Their early production from these vertical wells on the first two wells has been somewhat disappointing, but certainly not conclusive at this point. Both wells are currently flowing about 100 Mcfe a day and are experiencing some water loading problem.

Due to the lack of infrastructure in this area, these wells were shut in close frac from an extended period of time while the pipeline was being built. We are currently evaluating several options and to restore production back to the earlier close frac rates prior to the wells being shut in. Due to the performance of these wells, we will delay fracing the other three wells that have been drilled until the pipelines hook up is complete which should occur in the next one to two months.

We'll start drilling our first horizontal Haynesville well later this month and we'll plan to keep one or two Unit bridge drilling in the Haynesville in the Shelby County area during the third quarter of this year.

In addition to the Shelby County activity, in addition to our activity, another operator has just announced plans to drill the horizontal Haynesville well that's just adjacent to our acreage block and this should also give us additional information and to evaluate our block.

The current plan for 2009 is to drill a total of approximately nine vertical wells and one horizontal well in Shelby County at an approximate cost of $25 million.

In addition to the Shelby County, Haynesville, we also plan on drilling three vertical Haynesville wells in Harrison County, at an approximate cost of $6.5 million.

In conclusion, 2009 continues to be challenging year but we are very excited about the opportunities that we have both in Granite Wash and Segno fields and then in our new areas at the Haynesville and Marcellus Shale. We're also planning to pursue strategic acquisitions, utilizing our strong balance sheet during the second half of this year.

As Larry mentioned on the cost side, we will continue to aggressively bid all aspects of our drilling services and we will continue to negotiate with our bidders to reduce cost.

At this time, I'd like to turn the call over to David and discuss the financials.

David T. Merrill

Thank you, Brad and good morning. EBITDA for the first quarter of 2009 was $99 million, a decrease of 37% from 157 million in the fourth quarter of 2008 and a decrease of 44% from 178 million in the first quarter of 2008.

For the first quarter of 2009, the oil and natural gas segment contributed 62% of EBITDA, contract drilling contributed 37%, and midstream 1%.

EBITDA for the first quarter decreased from the fourth quarter in all three operating segments. For the oil and natural gas segment, the decrease was primarily attributable to lower realized commodity prices, realized prices including hedges for oil, natural gas liquids and natural gas, decreased 35%, 29% and 2%, respectively.

Without the benefit of the natural gas hedges, realized natural gas prices decreased 23% versus the 2% including the hedges.

For contract drilling segment, the decrease was primarily attributable to a 45% reduction in the number of drilling rigs operating and as Larry mentioned earlier, a 14% decrease in operating margins per day before elimination of inter-company rig profit.

After the elimination of inter-company rig profit, our financial operating margins per day only decreased 6%.

Between periods, the reduction in average drilling rigs operating for our oil and natural gas segment decreased 75% while a decrease in average drilling rigs operating for third party customers decreased 42%.

For the midstream segments, the decrease was primarily attributable to a 7% decrease in blended back spread (ph) margins.

For the oil and natural gas segment, basis differentials in the mid top, net there in the first quarter improved from the fourth quarter level. For the first quarter of 2009, basis differentials for our natural gas production before the impact of hedges, averaged at $1.18 reduction from NYMEX, wherein the fourth quarter the differentials averaged $2.22 reduction from NYMEX.

Approximately 70% of our natural gas production is delivered at Centre Point East and Panhandle East, where differentials averaged $1.50 reduction from NYMEX during the first quarter of 2009, improving 49% from the negative differential of $2.94 during the fourth quarter.

While the balance of 2009 features indicate the average basis differential for Center Point East and Panhandle East is approximately $0.81 reduction from NYMEX, we realized the NYMEX future prices continue to weaken and looks to be headed to weaker levels.

We have hedged approximately 72% of our anticipated 2009 natural gas production at a weighted average delivery point price of $6.43 and approximately 76% of our anticipated 2009 oil production at a weighted average price of $61.49.

For 2010, we have hedged approximately 64% of our anticipated natural gas production at a weighted average delivery point price of $6.29 and approximately 46% of our anticipated oil production at a weighted average price of $61.36.

More detail on our hedges is disclosed in our Form 10-Q being filed with the SEC today.

Total capital expenditures from our operating segments for the first quarter of 2009 were $86 million. For 2009, our capital expenditures budget for all three operating segments combined is $290 million, unchanged from what we have talked about during the fourth quarter and does not include any amounts for acquisitions.

Budgeted capital expenditures by segment for 2009 are 200 million for the oil and natural gas segment, 77 million for the contract drilling segment and 13 million for the midstream segment.

The 2009 capital expenditure budget is anticipated to be funded from cash flow from operations.

The effective income tax rate for the 2009 first quarter was 37.8% and should approximate the rate for the year and will be 100% deferred as we currently do not anticipate any current income tax for 2009.

Our debt-to-capitalization ratio at the end of the first quarter was 10% with 163.5 million of long-term debt outstanding. We have a $400 million credit facility of which we have elected to have a current commitment amount available of $325 million. The credit facility matures in May of 2012. And as of April 1 of this year, the lenders under our credit facility completed their re-determination of our borrowing base... determining borrowing base to be $475 million, well in excess of our current elected commitment amount of $325 million and also in excess of a maximum facility amount of 400 million.

We are currently in compliance with all of the covenants contained in the credit facility and our working capital at the end of the first quarter was $103 million.

I would now like to turn the call over to Justin, our operator to take questions.

Question-and-Answer Session

Operator

Okay. (Operator Instructions) Okay. Our first question comes from Robert Christensen of Buckingham Research. Your line is open.

Robert Christensen, Jr. - Buckingham Research

Yes, thanks guys. The Haysville, let's come back to that and who is drilling next to you that is kind of horizontal that we should pay attention to?

Brad Guidry

Hey Rob, this is Brad. Just because stay the well...

Robert Christensen, Jr. - Buckingham Research

Okay.

Brad Guidry

Adjacent to our acreage line.

Robert Christensen, Jr. - Buckingham Research

And you are going to do your own horizontal, I guess nearby?

Brad Guidry

That's correct.

Robert Christensen, Jr. - Buckingham Research

When will you spud that well?

Brad Guidry

Later this month.

Robert Christensen, Jr. - Buckingham Research

And should we sort of condemn those first two vertical wells which are loaded up with water or?

Brad Guidry

No, I don't think we should condemn them at all. I think at this point, it's just too early to tell. A part of the program we are doing in this area some like LIFO exploration. The plan was to drill verticals out here, to hold the acreage, the change to drilling the horizontal well is certainly a change to find out what the economics of the Haynesville is in this area.

On a positive note, something else that happened I didn't mention is down kind of in the Southwest part of the County, Southwest Energy announced the rates on one of the wells I think Common Resources was the operator, seven or eight million to say horizontal Haynesville (ph) and that puts us within the limits of Haynesville. I mean we feel very good about productive nature of our block. It's just a matter at this point when those vertical wells decline.

And we really do think a lot of that could function the one wells is out there to work for six months (Inaudible). That we want to a well, see a horizontal well. Obviously when you trying to say rates you can't drill them with funnels in a timeless fashion. So, it shows when you do this.

Robert Christensen, Jr. - Buckingham Research

You'd mentioned that last time this is really confirming your I guess strategy there. Anybody to the North of you guys that has had successful horizontals like in Phenola (ph); just trying to see who is around you that we can cite for success or failure?

Brad Guidry

Yeah immediately north of our block, there is actually a horizontal James well that was drilled that had a pretty high IP of 10 to 14 million of day range that (Inaudible) drilled.

Robert Christensen, Jr. - Buckingham Research

Okay.

Brad Guidry

But we don't have any data on that.

Robert Christensen, Jr. - Buckingham Research

Yes.

Brad Guidry

Immediately North of this, the horizontal, I have not seen anything. If you look at Shelby County and Harrison County I mean if you look at permits that are out there, it lights up.

Robert Christensen, Jr. - Buckingham Research

Yes.

Brad Guidry

There is kind of wells being drilled. Now as I mentioned that Chesapeake is adjacent to that block and then Chesapeake is also drilling another well to the East of us where we have other smaller acreage wells over there. So, I mean activity level is there. Just like now the actual production results just aren't there. Now with the Southwest announcement down there, I feel really strong that (Inaudible).

Robert Christensen, Jr. - Buckingham Research

Yes. And just on the rig business; what's ... are any rigs being cold stacked at the present time or what's the status of some of the equipment right now?

Larry Pinkston

I mean in fact they are bothering me. There are several, a lot of the rigs mostly in this smaller sizes. Its some of our big rigs, they're just not in market form right now. So, we're not really trying to market them. There is nobody in the market. So, in affect they are cold stacked.

Robert Christensen, Jr. - Buckingham Research

And do you have rigs going towards Pennsylvania anytime soon?

Larry Pinkston

We're still working on that. Nothing is in place right now for of the schedule.

Robert Christensen, Jr. - Buckingham Research

Okay. But that's part of your strategy to be serving an integrated operator up there at some point?

Larry Pinkston

Yes, that's still our strategy.

Robert Christensen, Jr. - Buckingham Research

How about in the Haynesville, I mean like in North Louisiana, is there a way for your company to use rigs to gain interest in leaseholds? I think you'd mentioned that as a possibility at negotiating tool or could you just kind of briefly update us on that?

Larry Pinkston

Still frankly if there's a possibility that's coming, we've not seen it. I mean its not, nothing has transferred to date but as we get closer to some of these lease explorations that different companies have and they like to capital. I think we're going to ... its not going to be the availability of rigs that drives it that we've seen over the last four five years. It's going to be the lack of capital and the short term currents left on the leases, that's going to be driving at this time.

Robert Christensen, Jr. - Buckingham Research

Thank you very much. I'll get back in line.

Larry Pinkston

Thanks Bob.

Operator

The next question comes from Pierre Conner of Capital One South, your line is open.

Pierre Conner - Capital One Southcoast

Good morning, gentlemen.

Larry Pinkston

Hello Pierre.

Brad Guidry

Hi Pierre.

Pierre Conner - Capital One Southcoast

First on the drilling side Larry; so the rigs that you currently have running, are any of those a term contract that are on standby. The operator is required to pay and are not actually operating. Are they all drilling?

Larry Pinkston

We have one in the Rockies that is in affect on standby until the steps or release, then they can go back in and start drilling again.

Pierre Conner - Capital One Southcoast

Okay, but okay. So the mix of what you have is, I suppose in the Permian, those are the smaller mechanical rigs, Gulf Coast more your electric and sort of 15 or 20,000 foot capable. Can you give us some color on sort of the mix of these 39 you currently running?

Larry Pinkston

We have no rigs on the Permian.

Pierre Conner - Capital One Southcoast

Okay.

Larry Pinkston

That's a market we are not in. The majority of the rigs that we are running are going to be the 1,000 to 1500 horsepower rigs.

Pierre Conner - Capital One Southcoast

Okay. What can you give us on an outlook then? Given you're at the 39 now, one of those might go back. Well 39 are contracted in terms of where we will be next quarter on count and rate?

Larry Pinkston

Sure, you don't want to fill the natural gas prices in.

Pierre Conner - Capital One Southcoast

I put you on the spot.

Larry Pinkston

The rate of decline. I agree with everybody else who said that. As you're running lesser rigs...

Pierre Conner - Capital One Southcoast

Right this math.

Larry Pinkston

But I think the rigs that you're going to see coming off contract, the next few ones are going to be more, as some of the rigs has been on term and not been utilized necessarily, because the economics are there and that's going to be slower out than what we've seen over the last three or four months. And we've never been a big long-term contract player. And most of our rigs are under some pretty short-term either weld well or less than six month contracts. But I think the rate of the decline is going to slow that.

I don't know whether that's going to be this quarter or next quarter when it bottoms out. I mean, I think, we'll get down to a more... much more of a stabilized rate here for a while and see what gas prices are doing. I know everybody setting all operators and everybody else are sitting on side lines to see how fast this gas supply comes down and that's coming. That's what's going to give us some optimism as to the timing of when this nearly turns around as how fast the supply falls.

Supply and demand will ... they will cross again, it's a great thing about this industry as it doesn't stand up with (Inaudible).

Pierre Conner - Capital One Southcoast

Right.

Larry Pinkston

timing wise Bob, second quarter utilization for us and the industry is going to be lower definitely than what it was first quarter, third quarter.

Pierre Conner - Capital One Southcoast

But Larry, do you think that from here, do you know of existing of your 39 that currently running that your customers have said okay as soon as we wrap this up we're done, or...

Larry Pinkston

Yeah, we have a couple of rigs that fit into that category. I think one of that in June and other ones in July or something. But, we are starting to have been, lot of people that ... a lot of operators who got completely out of this quick drilling period back in to fall and early winter. They are coming back and starting to talk about drilling one well here and one well there.

So where do you have enough of those ones and twos is to offset the...

Pierre Conner - Capital One Southcoast

The lay down.

Larry Pinkston

Funds coming off. I don't know whether that's going to happen. But it think we have two now that are under possibly three that's under term contract that the progresses since once the terms have prepared (ph) I wonder, that I want to remain (ph).

Pierre Conner - Capital One Southcoast

Okay. I appreciate, you had given some color on that and I will try to search with that sort of sequential expectation might be. And I think some activity colored, then the mix is going to be the issue on the rate, but are you seeing this ... any of this spot waiting for any of these where the guys are talking about ones or twos coming back.

How much lower is that rate discussion versus ... sequentially, where they might be one to pick it up, as they are picking up because the rates are coming down, I guess is my question?

Larry Pinkston

Well it's not just the rates Pierre. It's the cost of drilling in total.

Pierre Conner - Capital One Southcoast

Okay.

Larry Pinkston

Frac cost, pipe cost, and everything else is turning to come back down or have come down enough to some of the fields where $4, $3 gas wouldn't work. And whether these prospects are drilling again by lease expirations or I don't know what the situation is for all of our customers. But, day rates from the peak on a 1500 horsepower rig it is down in the neighborhood of 25 to 35%.

Pierre Conner - Capital One Southcoast

Okay, that's helpful.

Larry Pinkston

That depends on how well the rigs are equipped.

Pierre Conner - Capital One Southcoast

Yeah.

Larry Pinkston

That's what drives our skidding (ph) systems or ...

Pierre Conner - Capital One Southcoast

Okay. Just a couple of quick ones more guidance related I guess may be for David. Just given where we are on cost, you mentioned or I guess Larry talked about cost coming down, what would you say LOE rate and DD&A rate, do you have some perspective on those?

David Merrill

LOE, LOE for the second quarter will be somewhere right around where we were for the first quarter.

Pierre Conner - Capital One Southcoast

Okay

David Merrill

And DD&A rate, the DD&A rate with the current commodity environment, somewhat of a challenge. If all things were equal and if prices ended up being at the same level as they were at the end of the first quarter, we didn't have negative revisions to reserves which ends up giving you a lower denominator at amortized your cost.

Pierre Conner - Capital One Southcoast

Yes.

David Merrill

We would adjust from where we were at the first quarter to round $1.80.

Pierre Conner - Capital One Southcoast

Okay.

David Merrill

So we were 2.32 in the first quarter and we'd be around a $1.80 assuming no negative revision.

Pierre Conner - Capital One Southcoast

Okay. And last one, just these NGL prices are so low it just surprised me, just wondered if there is any, has there been any uptake since the average of the first quarter with any kind of summer improvement? I did not ask you about gas prices but I am ask you about NGL prices.

David Merrill

No there hasn't been much change.

Pierre Conner - Capital One Southcoast

Nothing, okay. I am going to recycle back gentlemen, appreciate all the information.

David Merrill

Thanks.

Larry Pinkston

Thanks Pierre.

Operator

Our next question comes from Andrew Coleman of UBS. Your line is open.

Unidentified Analyst

Good morning gentlemen. This is actually David Deckenbell (ph) filling in for Andrew.

Larry Pinkston

Hello David.

Unidentified Analyst

Just looking for a little bit of color on the test impairment, I want to know if you can give us any breakdown or what percentage of that write-down was advocated towards spuds? That was mostly related to spuds or if there was some what of a PDP sale?

Larry Pinkston

Its primarily David, it's primarily PDP oriented. With our price percentage being in the 20% range, we don't have a high degree of value on those. Obviously the big driver was a change in natural gas prices as we did the discounted cash flows for the life of the properties and it certainly made certain of those properties uneconomic over the years than they were at the fourth quarter. But prices, natural gas prices used from fourth quarter to first quarter were down 36%. So that was the primary driver.

Unidentified Analyst

Sure. Thank you. And your liquidity position here is fairly strong, but looking at the CapEx profile can you give us a sense of how much of the CapEx budget is related to non-op?

David Merrill

Related to what?

Unidentified Analyst

To non-operated interest?

Larry Pinkston

The majority of CapEx is tied to the operated wells. We have ... we tend to have around 45 to 50% working interest in overall in the wells, and then gross wells we drill but the CapEx is going to be more tied to operated wells.

Unidentified Analyst

Okay. Fair enough. I guess moving to the drilling side real quickly; of the 39 of the contracts right now, is that about ... including about 12 to 14 that were on term contract or on six months of the year?

Brad Guidry

We had a ... David we had a ... of what you would characterize as long term contracts or at least ones have started out that way. We had about 18 that were on long term contracts.

Unidentified Analyst

Okay.

Brad Guidry

Those are ... some of the long-term contracts are up for renewal starting in the next quarter.

Unidentified Analyst

On the rig side, right now are we still seeing sort of a 5,000, four to 5000 a day rate discrepancy between what seems (ph) with the term contract rigs versus more of the spot work.

David Merrill

That's a pretty good range. Again, it depends a lot on how the rigs were equipped, what the rigs have on them (ph) in locations, different areas are a little more competitive than some areas. But that's going to get most of them.

Unidentified Analyst

And how many of the rigs right now are working or unit drilling?

David Merrill

Three.

Unidentified Analyst

Okay. Thank you very much guys, good job in the quarter.

Larry Pinkston

Thank you, David.

Operator

Next question comes from Jim Rollyson of Raymond James. Your line is open.

Marshall Adkins - Raymond James

This is actually Marshall.

Larry Pinkston

Hello Marshall. Certainly in the B-team today

Marshall Adkins - Raymond James

Yeah I was in the B team. Let's focus in on the drilling side a little bit. Dave any, can you give us sense by quarter when those term contracts roll off?

David Merrill

Of the 18 that we're talking about?

Marshall Adkins - Raymond James

Right.

David Merrill

We've got five in the second quarter, two in the third quarter, six in the fourth quarter, and then is five that go beyond 2009 and into as late as the fourth quarter of 2011.

Marshall Adkins - Raymond James

Okay, that will help from the modeling perspective. It sounds like and I just want to make sure I heard it right that you are seeing some stabilization in activity. Again, none of us are going to call it absolute bottom but it sounds like things are starting to stabilize. Did I hear your tone right on that?

Larry Pinkston

Some similar to stabilization Marshall.

Marshall Adkins - Raymond James

Definite may be then.

Larry Pinkston

Definite may be.

Marshall Adkins - Raymond James

Alright, the rig sale. Where does that show up on the income statement and kind of walk me through your thought process on selling off, lowering assets and stuff like that?

David Merrill

Marshall I'll answer where it's located. We did not have it located in the segment standalone financials for the drilling segment. If you look in other, there is other revenue.

Marshall Adkins - Raymond James

Right.

David Merrill

Combined and that's where it's included in the other revenue.

Marshall Adkins - Raymond James

I know the sales were a little higher than you were modeling?

David Merrill

Okay.

Marshall Adkins - Raymond James

And what is your thought process on additional sales?

Larry Pinkston

If we find ... again this is all condition on achieving our price we want to have out of some of these rigs, but some of these lower-end rigs that we've got, lots of them, if we take capital out of that, inventory that we don't see using in the next 12 months, 18 months at the minimum and our thrust is to grow the quality of our rig fleet, put it back into either whether its a components on different rigs or on new rigs on sales to be in a position to be able to do that. But it's by no means a far sale kind of situation. I mean it's ... we sort of priced them so that was on basis price rate, we don't sell it.

Marshall Adkins - Raymond James

Not worried about those rigs come back and compete with you price?

Larry Pinkston

This one led the Mexico, Baha (ph), so we are not worried about that one.

Marshall Adkins - Raymond James

All right. Margins and day rates held up remarkably well for the quarter. Did you ... were there some term contracts that were accelerated into the quarter or kind of what makes you and why first quarter seeing so much better then I guess your peer group?

Larry Pinkston

Other than the ... that's evident, I mean. There was nothing unusual coming through the rigs side, no contract termination payments, none of that Marshall it was, lot of, I mean some of that goes to... some of that contracts rolling off in the first quarter are renewing or being extended, but its some continuation of what we saw the rights that we were getting in the fourth quarter going into the first quarter. And again the thing we've always emphasized which we're not happy with our word, where our costs are today, Marshall but that's something ... that's where we make the difference as is only cost side of equation.

Marshall Adkins - Raymond James

Well, and on that line, some ... again some of your peers have realized some severance costs and other kind of one time fees as they laid people off. And I didn't see anything specifically broken out on your side, but it appears that obviously you have been cutting cost pretty quickly, is that right?

Larry Pinkston

Yes, we have. Remember we shutdown field officers in December. I had a pay rate reduction at the end of December and we did a lot of stuff earlier than many of our peers did and I wish I could say that it's all over with. In spite, that we continue to monitor as we go forward.

Marshall Adkins - Raymond James

Okay. Last question for me. Several months ago you had mentioned that you are kind of looking at overall well cost including frac and pipe all that stuff coming down 35 may be even 40% from peak to trough. Now that we're three or four months into it, you still think those numbers are going to end up being right?

Larry Pinkston

Yeah, exactly certain components of the drilling or the day rates are about in that range. Frac costs are coming down. Pipe costs are definitely in the 50% plus range cheaper. That's a big here flow forward as to what they are going to be doing that there is a small incidental cost and they are probably not down to that level yet, Marshall but, it's all headed in that direction.

Marshall Adkins - Raymond James

But overall are you still thinking cost of drilling well from the peak down 35% plus?

Larry Pinkston

Easily in the 30 to 35% range, Marshall.

Marshall Adkins - Raymond James

Okay, great thanks for the help. I'll meet you.

Larry Pinkston

Thanks.

Operator

Okay. Our next question comes from George Gasper of Robert Baird. Your line is open.

George Gasper - Robert Baird

Robert Baird, good morning to everyone.

David Merrill

Good morning.

George Gasper - Robert Baird

First question on just continuation on these rig questions and maybe you've covered this in part. What rigs are you committed to construct at this point and what kind of contracts are signed on them and what negotiations ... where are you on negotiations on those particular contracts?

Larry Pinkston

We have one rig, that's, it would take up completed rigs it's a national rig for schedule to take it early in the fourth quarter, George. That's the only rig we have plans for right now bringing up this year.

George Gasper - Robert Baird

Okay

Larry Pinkston

And that has a few year contract.

George Gasper - Robert Baird

Are you comfortable that that is going to happen or is that...

Larry Pinkston

We are not comfortable with that much of anything.

George Gasper - Robert Baird

I am sorry, what was that?

Larry Pinkston

I this environment my comfort level is pretty small on about everything.

George Gasper - Robert Baird

Okay. All right secondly, on your ceiling test (ph) used in the non-cash charge, what were the prices that were used on that ceiling just under? How does your hedging interface with that ceiling test on that gas that you have got committed at higher prices, can you explain that?

David Merrill

Sure, that's big question George. The prices used in the sealing test were ... as you know under the current rules we use the realized prices on the last day of the quarter for oil and natural gas. The oil price used before differentials was 49.66 and the natural gas used before differentials was $3.63, liquids were 46.96. The hedges ... the value of the hedges what we had in place through their duration is included in the sealing test and the value at the end of the first quarter was $198 million. So, that helps reduce the sealing test right down.

George Gasper - Robert Baird

I see, I see. So that's a deduct in the sealing test basically. The 198, is that what you are saying?

David Merrill

Everyone is saying it is, it makes the ceilings ... it lessens the sealing.

George Gasper - Robert Baird

Got you. Yeah. Okay thank you.

David Merrill

Sure.

Larry Pinkston

Thanks George

Operator

Our next question comes from Pierre Conner of Capital One South. Your line is open.

Pierre Conner - Capital One Southcoast

Thanks for letting me back in. I can get Brad back in the middle of this. Brad, I've got to go back to the Haynesville. So the Shelby wells that where you frac but didn't get cleaned up quickly. Again I guess I asked last time a little bit about the completion technique and we're hearing a lot more about changes in completion technique that is to say slick water versus heavily polymer fluids and I want to know if part of your work considers changing. What did you initially? What about the completion on those?

Brad Guidry

Initially they were of the two that we frac without slick water. Right now we're still a little away from frac in these next wells and we haven't decided which way. But you're exactly right. And part of what we've done is we've joined the core consortium out there. I mean we're trying to get out hard data on the right way to frac these. We have certainly seen that some of the companies people want to work with gel frac to get the profit plays. We're looking at the several (ph) issues out there, certainly looking at the cog (ph) issues of having those wells shut in to that point.

And the thing we've got to remember certainly in this area I mean its like on a weekly basis, things change out here with both data that's made available through public source, on an internal data again. So it is definitely a loose target. At this point what we're planning on is to re-stimulate one of the two wells that we drilled ROE. Basically we frac it at this point the plan will be to re-frac it with slick water. In terms of the issues we're trying the determine is the damage out there caused, because of what slick water frac or because the well was shut in for an essential period of time.

I mean the first well we drilled out there, we first tested it. It was flowing stable at about 800 Mcf a day and then COF was about two million a day on those wells. So the first thing we want to determine is can we just go back and give that rate and minimize the damage that we make as a curved from the well being shut in. But as far as future fracs, all I can tell you that it is looked at weekly and the changes we will modify that as we get hard data to do that.

Pierre Conner - Capital One Southcoast

In a way in on the propend (ph) side of that too Brad?

Brad Guidry

I'll have to get back to you on that. I'm not sure I can really speak.

Pierre Conner - Capital One Southcoast

I'll get you offline. Okay, that was just my follow up on that. I appreciate gentlemen.

Brad Guidry

You bet.

Operator

(Operator Instructions) Okay, at this time, I am showing no further questions.

Larry Pinkston

We want to thank you for joining us this morning on the call and we hope to be ... we're already going to be on the road over the next two or three weeks and we hope to be able to see many of you while we're out. If not, call us and we'll come to see you.

Thanks. Good bye.

Operator

This concludes today's conference call. You may now disconnect.

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