Jun 23, 2008
Executives
Steven Williams – Chairman and Chief Executive Officer Rick McCullough - President and Chief Financial Officer
Analysts
Phil McPherson - Global Hunter Securities David Tameron - Wachovia Joel Musante - C. K.
Cooper & Co Steven Rice – Morgan Stanley Mark Lear - Sidoti & Co Leo Mariani – RBC Capital Markets
Operator
Greetings, ladies and gentlemen, and welcome to the Petroleum Development Corporation Q1 2008 earnings conference call. (Operator Instructions) It is now my pleasure to introduce your host, Mr.
Steven Williams, Chief Executive Officer for Petroleum Development Corporation.
Steven Williams
Thank you very much. Joining me also today will be Rick McCullough, the President and Chief Financial Officer of Petroleum Development Corporation.
Get the necessary business out of the way first: we do have a disclaimer here with regard to forward-looking statements, and since we are providing an update to our guidance for 2008, it certainly is germane to the conversation today. I would encourage you to take the time to read it of course.
The forward-looking statements are estimates and subject to change with change in conditions. In addition, we don’t commit to update this forecast in the future, except as such time as we deem it to be appropriate.
With that, I am going to move along into the operations update first. A few quarterly highlights maybe to start the presentation off today.
I am happy to say that our quarterly production was in line with the guidance that we provided in early February and 59% above the first quarter of 2007 production. Some of the key financial metrics with the comparison here to the first quarter of 2007 also: our oil and gas sales were up 111%, and that’s through a combination of prices and production.
Certainly, the strong price environment for oil and for natural gas was important to that as were the previously mentioned increases in production during the period. The average sales price per Mcf equivalent was up 32% to $8.45 or $1.7 above our February guidance.
That’s driven by continuing increases in prices through the quarter for both oil and natural gas. We were very pleased to see in the Rocky Mountains the response that we anticipated to the start up of the Rockies Express Pipeline as the basis differential between the Rockies and the NYMEX closed down to more normal historical type levels, and then what we have seen certainly during the latter part of 2007.
Adjusted cash flow from operations, which is a non-GAAP measure, which is basically GAAP cash provided without the changes in assets and liabilities increased by $20.6 million or 104% to $40.4 million. So, good cash flow from the quarter − one of the reasons that we decided to increase our CapEx budget, which we will discuss later in the presentation.
The adjusted net income, another non-GAAP measure, increased to $11.2 million or $0.75 per diluted share, and that included the impact of a $3.2 million non-recurring G&A charge in the first quarter associated with termination costs with the resignation of our previous President. If you take the after-tax impact of that non-recurring charge, we would have had about $0.89 per diluted share in the first quarter, which is close to in line with a number of our analysts.
In addition to those things, we also during the first quarter have increased our use of fixed price derivatives for 2008 and beyond in order to secure the benefits of the current strong energy price markets. Certainly, like everyone else, we don’t have a great crystal ball for the direction of the future, but we do know that at these price levels that we could lock in the ability to execute on our business plan and in fact to accelerate some development in 2008 and beyond.
We have taken advantage of the pricing environment to assure ourselves that some of the cash flows will be available at these kinds of pricing levels through the use of derivatives. The downside of the derivatives, and you can certainly see the impact in the first quarter financial results is, because we do not use hedge accounting, the value of the out-of-period derivatives or changes in values of out-of-derivative periods are written through our income statement.
Consequently, we have a large non-cash loss for the unrealized portion of derivative losses in the first quarter, which can make it a little bit difficult to sort your way through exactly what’s going on with the company. But we are doing our best to try and provide the information for you of both what we would do with and without the derivative type losses.
Looking at pricing more specifically for both gas and oil, as you can see, the oil prices through 2007 increased significantly from quarter-to-quarter. Strong oil prices throughout our three different operating areas, ranging from $81.08 in the Rockies up to a high of $96.13 in the Appalachian Basin and with Michigan, which has relatively small amounts of production in between the two.
We expect to continue to see strong price performance in 2008. We really don’t see a trigger event that would result in a collapse of oil prices at this point in time.
Nonetheless, we think it’s prudent to be able to take some of that risk off the table by using swaps and collars to lock in the benefit of the pricing environment. Natural gas prices likewise performed very well in the first quarter.
Again, as I mentioned, a key factor there was the start up of the Rockies Express Pipeline. We also had cold winter weather, which has resulted in good storage draws.
We are entering the summer with storage in the range of the five year averages or even slightly below, which we think is a positive as far as prices going forward. Besides the cold weather, I think maybe the other key factor in the strong natural gas prices has been the high oil prices, which results in LNG supplies which compete directly with oil in some of the world markets being diverted from the United States to those other markets.
As a result, that certainly helped with the supply/demand situation for natural gas domestically, and it helped to keep the natural gas prices at historically high levels. Looking a little bit more at production.
We mentioned earlier we had about a 59% increase year-to-year in the first quarter of 2008 compared to 2007. That is a new record of 8.5 Bcf equivalents for the first quarter of 2008 and it was right on track with our original 38 Bcf production for 2008.
Because the CapEx increase only impacts production late in the year, we are also online with our revised 38.6 Bcf equivalent for 2008. The CapEx increase does have an impact on 2008, but it’s pretty minimal because the majority of the wells are only just starting to be drilled; won’t go in line until late in the year and as a result will have a much larger impact on 2009 and beyond.
Breakdown by oil/gas. We were about 82% natural gas in 2008 first quarter and 18% oil.
The Rocky Mountain region altogether accounted for about 84% of the total production and certainly continuing to be the key to the success of the company at this point in time and through 2008. Next slide, looking into the reserves.
We did provide some reserve guidance with our analyst meeting. This is really more or less a repeat of that.
At this point in time, we are still anticipating at least 750 Bcf accrued reserves at the end of the year. The additions at this point in time are through the drill bit.
We don’t have any identified acquisitions, but we certainly are always in the market for acquisitions. The reserve improvements for 2008 we would expect to be in our three areas in Colorado as well as the Appalachian Basin.
At this point in time, we don’t have a lot of activity planned for our Michigan area. But we do think there is some potential for reserve additions in 2008 for Marcellus Shale and Barnett Shale.
As I mentioned earlier, we are getting ready to complete our first well in the Barnett Shale in June and we will begin doing some work in the Marcellus during 2008, either specifically targeted at the Marcellus or possibly by drilling some of our other wells deeper depending on the area that they are located in. Next slide shows the drilling activity over the last six years.
I think one of the things this illustrates is our move away from partnerships over that time period as the yellow indicates wells that we drilled for others, the blue is wells we drilled for the company. In 2008, we’re anticipating now about 380 gross wells.
That’s an increase of 20 gross wells from the previous guidance associated with the CapEx increase and will yield 360 net wells compared to 340 net wells in the earlier guidance for 2008. The majority of those wells, over 300 of them, will be in the three areas in Colorado and about 75 wells in the Appalachian Basin with a handful of other wells in areas like the Barnett Shale.
Production forecast for 2008. Here we have on the bar chart the February guidance by quarter updated for the CapEx increase in 2008.
We now have a 38.6 Bcf equivalent total estimate for 2008 with the 0.6 Bcf increase as I mentioned earlier. The first turn-in from the incremental wells won’t incur until late in the year.
The estimated net exit rate for 2008 we anticipate to be near 132 million cubic feet per day. That’s up from the analyst day number of 120, so about a 10% increase in the exit rate as a result of the incremental drilling rig in the wells that go in line from it during the year.
At this point in time, we do believe we are on track to meet this production forecast for the full year, and they are over the year basically in track with the original forecast provided at the analyst day in February. Key to this is an aggressive second, third quarter completion program, and I’ll talk about that a little bit more on one of the later slides here.
In addition to the completions, we also have some additional compression in our NECO area that we are expecting to have come along here later in the year. Next slide.
For those of you who like to build detailed models, we do have the original forecast, information, and a more detailed breakdown by area of production for both the Rocky Mountain, Appalachian and Michigan regions and then within the Rocky Mountain area for Wattenberg, Grand Valley Field, NECO and North Dakota. Some of the key developments in the second quarter, looking forward, that we think will have a major impact on the year is our recently announced increase in the capital budget in Grand Valley Field.
We added $40 million that we had in our original plan envisioned releasing one of our three rigs for the summer and then picking it back up in the latter part of the year. We now plan to run that third rig through the year and that will net about 20 additional net wells, both gross and net for the company.
We have underway an addition to the gathering system in our NECO area. It’s key to being able to get a number of the wells that currently have been drilled, but are not in production, into production.
As of the end of the first quarter, altogether, we have about 160 wells that had been drilled and/or completed but were not yet in production. This is a key to the wells in the NECO area getting into production.
We are in the process of doing a detailed technical evaluation of the Marcellus formation. We are nearing completion of an initial assessment of our deep rights or Marcellus rights in that area and we are currently estimating they will have about 35,000 acres where we have the Marcellus rights.
The next step is really to assess how attractive they are based on their location within the areas. So we know what we have in terms of the acreage.
We don’t know at this point in time, though, how attractive we think it might be. In addition to NECO, we also have a number of well backlogs in the Grand Valley Field.
This is really entirely anticipated in that area. We did for the first time drill on top of the mesa during the winter of 2007, 2008.
But while we drill up there, we really don’t want to carry out the completion activities during the winter, for both cost and economic reasons, if we can hold our costs down and minimize the impact by not completing during the winter. But that does leave us with a significant backlog of wells in that area that are in the process now of being completed and turned in line.
Hence, you can see when you look at the production history and forecast, we really had about flat production from the fourth quarter of 2007 to the first quarter 2008, just slightly up. We anticipate significant increase as we move farther forward in 2008 as the Grand Valley wells and the NECO wells are turned into production.
Then finally, we are at this point in time anticipating our first Barnett Shale completion in early June. The pipeline that we are waiting for is nearing completion and if it’s not then, it should be very shortly after that that well gets completed, we’ll start to get a sense of what our results might be at that point in time.
Overall, I think our drilling activities are continuing pretty much on schedule and with the results that we would expect, which is the characteristic of the low-risk type of development drilling prospects that the company likes to focus on. That completes the operations update.
At this point in time, I would like to turn it over to Rick for the first quarter financial update.
Richard McCullough
Thank you, Steve and good afternoon. The first quarter was all in all a very strong quarter financially for the company.
It was one of continued increases in production, higher realized gas and oil prices and thus higher adjusted cash flows and adjusted net income. Our quarterly revenues of $72 million were up 26% over the fourth quarter 2007 levels alone, and up 65% over average 2007 levels.
We continue to see improvement in pricing in all our basins of operations. With our weighted average realized prices of $8.45 per Mcfe, that’s up almost 25% over the fourth quarter of 2007 and has contributed substantially to both higher dollar and per unit operating margins as you can see on the bottom of this chart.
Our EBITDA for the quarter was down due to unrealized non-cash losses on our derivatives as of March 31, 2008 and we’ll talk about the hedging losses further. However, if you add back these non-cash losses, as you can see on this table, you see that EBITDA adjusted is more comparable to fourth quarter 2007 results and the same can be said for adjusted net income.
As you can see in our filed 10-Q results and in subsequent slides, we continue to experience increased operating and G&A costs, although the latter would have actually been down for the quarter, if not for some unusual non-recurring expenses that we will address later. Our DD&A and G&A expenses remained at comparable levels to those that we experienced in the fourth quarter of 2007 with our per unit rates of $2.49 and $1.16 per Mcfe respectively.
As I mentioned earlier, our quarterly G&A expenses of $10 million included a $3.2 million non-recurring charge related to executive transition costs. When adjusted for this non-recurring charge, our per unit G&A rate for the quarter would have been $0.80 per Mcfe.
The one area of somewhat disappointing results in an otherwise great quarter was in the area of our lifting and total production cost. We have seen our total production expenses increase by $2 to $3 million per quarter during the latter part of 2007 and continuing into the first quarter of 2008.
This is in addition to increases we have seen in production taxes associated with increased oil and gas prices. A major portion of the first quarter increase is associated with our operations in the Piceance Basin and is related to seasonal snow removal, road maintenance costs associated with the Garden Gulch Road and other third party expenses.
While many of these expenses are seasonal in nature, going forward throughout 2008, we do expect higher than usual road maintenance expenses associated with preventive stormwater matters and expected new state regulatory requirements. On the next slide, you can see that the higher cash flows during the first quarter and as a result of a bond financing transaction that we completed in February, our total debt is actually down over fourth quarter 2007 levels and our available liquidity has increased substantially and was over $234 million at quarter end.
With the increased cash flows, we continue to maintain strong interest coverage levels and our debt-to-cap ratios remained well within our target ranges. The increased liquidity and improving operating cash flows provide us a great deal of flexibility in meeting our CapEx needs of 2008 and beyond as well as providing us capital for opportunistic acquisitions.
On the hedging update, in light of the strong commodity price markets, our increased debt levels and the importance of our development drilling program for 2008 through 2010, we have substantially increased our total hedge positions, increasing both our hedged volumes as shown in the chart below and the tender of our hedges with some of our positions extending forward to 2012. As you can see, as of the end of March 2008, we have approximately 48 Bcfe of future production hedged with swaps, collars and floors.
In so doing, we have locked in very attractive pricing on approximately 60% of our remaining 2008 estimated production of oil and about 50% of our gas at $91 dollar per barrel and $7.79 per Mcfe respectively. In addition, we have another 14% of our 2008 estimated production with collars at weighted prices of $7.57 to $10.43.
However, because of these positions and increasing forward prices, we recognized a $39.9 million non-cash unrealized loss on open positions and realized a $2.4 million loss on expiring positions during the fourth quarter. I would also note on the slide that shows the hedges in place that we also have about 50% of our oil production for 2009 and 2010 locked in at prices above $90.
Moving now to an update on our guidance. We are updating guidance today to reflect increased gas prices.
The numbers that we’ll be sharing reflect both the hedging results that we just talked about for 2008 and for any un-hedged volumes we’ve used current forward prices as of May 1. On the cost side, we’ve increased our G&A estimated expenses by $6 million related to the executive transition cost, most of which we’ve recognized in the first quarter, but we will also have some additional costs associated with Steve’s retirement and other transitioning expenses.
We actually think this estimate is probably going to turn out to be conservative. We’ve also increased our production expenses.
When we prepared our first forecast, there were some expenses that were excluded. As our business changes, and we’ve talked about it in the past, the transition away from the partnership business, we excluded some of the production expenses associated with partnership activities.
We have now included those. We updated production expenses for the increased production taxes and also the expenses that we just discussed in trending up for the last part of 2007 and early 2008.
As you can see, our updated guidance, we’ve slightly revised our production upwards to reflect the recent decision to increase our CapEx and maintain that third rig drilling from 38 Bcf to 39 Bcf. On the oil and gas revenue side, there is a substantial increase due to the increase in forward pricing today versus when we prepared our forecast.
On adjusted EBITDAX, you can see about a $40 million increase. We’ve realized probably $10 plus million of the increased gas pricing in the first quarter.
We have probably locked in another $35 to $40 million through our hedges. But all of this, we believe, that offset by the increase in expenses should still drive about a $40 million increase in EBITDAX.
You can see the increased levels of CapEx that we disclosed earlier this week. On the next page, here is where you can see the substantial increases in some of the operating costs, more specifically the production cost.
Productions costs, we’re estimating upwards of about $0.30 to $0.40 per Mcfe and a total operating cost of about $0.45 to $0.60. Over half of the increase in these two categories that I was just pointing out is related to the fact that we left out some of the partnership production expenses in our first guidance and then increases associated with just increasing gas and oil prices.
Nevertheless, there are increasing expenses in these areas. Finally, you can see total debt to cap ratios are basically unchanged and also the total debt to adjusted EBITDAX.
When you look at all these numbers in summary as far as the 2008 guidance, I think as a result of higher gas and oil prices offset by higher production costs and slightly higher production, we’re still increasing guidance on profitability, cash flows and EBITDAX substantially. The last bit of information included in the presentation, I would just call your attention to, are reconciliations for EBITDA, adjusted net income and adjusted cash flow from operations.
This reconciles the GAAP numbers to the non-GAAP measures. That’s all I have for the financial section.
Steven Williams
Thank you very much Rick. That completes our presentation for today.
At this point in time, we’d like to open the floor for questions. Latania, if you can organize that for us, we’d appreciate it.
Operator
Our first question comes from Leo Mariani – RBC Capital Markets.
Leo Mariani – RBC Capital Markets
Quick question on the Barnett there. Just curious to see if you have had any acreage there recently and just give us an update on your position over there.
Steven Williams
Yes, Leo, at this point in time, we have the 8,900 acres in that area, although we’re continuing to do some looking around there.
Leo Mariani – RBC Capital Markets
Okay. Next quick question here for you.
Just trying to get a sense if you are trying to increase your oil and liquids production in light of the high prices and perhaps you could elaborate a little bit more on the slight production increase you have in your guidance for this year and how you think that spills over into 2009 as well?
Steven Williams
From the standpoint of increasing oil production, the principal way that we would have to do that would be to accelerate either the drilling or rig completions in Wattenberg Field. We are certainly pressing forward with that program as aggressively as we can.
We already had a pretty aggressive program in our model because even in February this year it was pretty clear that it was attractive to do as much work there as possible given the pricing situation. I think the incremental budget or the addition of the budget in the Piceance Basin and the Grand Valley Field will basically generate additional gas volumes.
There is very little oil production at all associated with that. In either case, the economics are attractive at the current pricing levels.
They are certainly even below the current pricing levels. We did feel like given the pricing environment, the incremental cash flows and our strong liquidity position that it was a good idea to retain the third rig and go ahead and push forward with increasing production above the levels we originally projected.
Leo Mariani – RBC Capital Markets
Okay. Thanks.
Operator
Our next question comes from Mark Lear - Sidoti & Co.
Mark Lear - Sidoti & Co
Good afternoon. I just would like a little clarity on the upped production guidance for 2008 and 2009 and just trying to get a feel for the activity in terms of increasing what you had previously stated in the Piceance and what the activity was looking back maybe to 2007 and get a feel for the kind of production growth associated with that activity?
Steven Williams
I can tell you a little bit about what we think the CapEx budget; to the broader question, I have to go back and pull some historical numbers out that I don’t think I can do out of my head. As I say, we are continually running the third rig through the summer where we had originally intended pulling it back.
I think if we started from the January analyst model even though 2009 and that is characterized as not a guidance for 2009.
Mark Lear - Sidoti & Co
Right.
Steven Williams
It assumes the same base level of drilling as in 2008. So what we would do by running this rig through 2008 is add an incremental 5.9 Bcf of production to 2009 on top of that sort of base level.
I think as we get closer to 2009, we will provide guidance for that year. At this point in time, starting from the assumption that we do more or less what we did this year and then later on, that increment is at least a good starting point.
Mark Lear - Sidoti & Co
But that 5.9 Bcf that I saw on one of those slides is from roughly 48 Bcf, if I recall?
Steven Williams
That 5.9 Bcf is from 20 incremental wells; it’s an additional $40 million of investment.
Mark Lear - Sidoti & Co
But that’s from on top of that previous guidance?
Steven Williams
Yes, on top of the 48 Bcf for 2009.
Mark Lear - Sidoti & Co
Right.
Steven Williams
Yes, that will be correct.
Mark Lear - Sidoti & Co
Okay. And just looking through the press release before, I just wonder can you state where the dry hole expense was incurred?
Steven Williams
The two dry holes were both in NECO and those are our 2,000 foot deep wells that completed are in the range of $250,000. So the dry hole costs associated with them is relatively small.
Mark Lear - Sidoti & Co
And then what was the other exploration expense?
Steven Williams
Some of it would be lease expenses. I think we may have had some associated with a well that was declared dry in earlier period.
Mark Lear - Sidoti & Co
Okay. All right, thanks a lot.
Operator
Our next question comes from David Tameron - Wachovia.
David Tameron - Wachovia
I’m going to beat this to death. For 2008 to 2009, what assumptions are you assuming for the Piceance rig count?
Steven Williams
Through 2008, we will run three rigs for sure.
David Tameron - Wachovia
Okay.
Steven Wiliams
Do we have three rigs running through all the way through 2009?
David Tameron - Wachovia
So rig count kept flat in 2009?
Steven Williams
Anticipate, for right now, assume three rigs through 2008 to 2009.
David Tameron - Wachovia
Okay. And if I look at this, the math, I think you said you had an exit rate in the presentation 132 [million cubic feet per day] and going to, if you average with the increase, it’s roughly 150 for next year, if my math’s correct at that 55 Bcf.
That $18 million a day, is that all expected to come from the Piceance or from Grand Valley?
Steven Williams
Next year, probably not. We’d continue to run the same program in Wattenberg; we have some production increases in all three areas, I think, probably.
David Tameron - Wachovia
Okay, all right. A couple of other questions.
If I look at where you are trading, and I don’t know who wants to take this, but for 2008, you’re trading at probably about 15 Mcf of proven reserves, just using that 750 Bcf number you’ve thrown out. What can you do as a management team to try to get that number higher?
It’s obviously significant; is there anything you can do? If you look at stuff like that, can you just comment; do you have anything you can give me on that?
Steven Williams
There is a lot of different metrics to look at for why you’re valued where you are. I think that, as Rick talked a good bit about the operating expenses.
I think we need to do a better job of addressing those. I think we already have addressed through the derivative positions and the strengthening markets some of the other half of that cash flow question.
What drives it is cost and, cost and revenues basically. I think one of the reasons that our Mcf valuation is maybe lower is because our net has tended to be low and during 2007, certainly wasn’t helped at all by the Rockies Express or the pre-Rockies Express gas market there.
So we need to look to get that yield up, and which ultimately in my opinion at least, I think that’s probably the reason that we are on the lower end of that valuation range. If you look at some of the other, we are valued fairly near or slightly above the middle I think on cash flow per share and other metrics on the dollars per Mcf of daily production or dollars per Mcf of reserves.
My personal feeling is they would probably both go back to what we’re netting out of production.
David Tameron - Wachovia
All right. One time you discussed the stock split or the potential for a stock split; where does that currently stand?
Steven Williams
The limitation on a stock split is one of the number of shares that we have issued or have [inaudible] basically. So at this point in time, we would not be able to do a 2 for 1 split.
In our proxy, we are asking our shareholders to approve an increase in the number of authorized shares. That would put us in a position where we would be able to do a split; something that certainly the Board is looking at and would consider at that point in time.
David Tameron - Wachovia
Okay. One more question and then I promise I will jump off.
If you go back to analyst day, with the increase in the guidance, you have hit your 2010 target in 2009. Any feel for 2010 directionally wise?
Should we just add the 6 Bcf on from 2009? What’s a good way to think about 2010?
Steven Williams
We want you to be able to keep making it bigger and bigger, a couple or three times, David.
David Tameron - Wachovia
Okay. I know you gave us 2008 and 2009; I’m asking for 2010…
Steven Williams
With your model, I’m sure you can model the additional Piceance Basin wells and their decline curves and then assuming we are doing an expanded program in 2009. We will see additional increases in 2010 off of that.
A lot depends on the pricing environment. With this pricing environment, we are also generating more cash flows than we were anticipating.
One of the limiters we were using in the model was that we didn’t want to exceed a certain debt to cap ratio. So if our cash flows are stronger, our production is higher, that gives us more flexibility to add incremental drilling or make acquisitions.
At this point in time, from our standpoint, that’s really guessing what will happen in 2010. But I think we are certainly positioning the company to be able to do more than what we have in those models.
David Tameron - Wachovia
All right, thanks Steve.
Operator
Our next question comes from Steven Rice – Morgan Stanley.
Steven Rice – Morgan Stanley
Good afternoon. Just had a question about the remaining partnership payment of $39.9 million.
Do you know when that payment will be spent? Should we look for that to be spent mostly in 2Q or spread evenly across the remaining quarters of the year?
Steven Williams
Most of it will be done in the second quarter. There will be some carryover into the third, but most should be done by the second quarter.
Steven Rice – Morgan Stanley
Thank you.
Operator
Our next question comes from Joel Musante - C. K.
Cooper & Co.
Joel Musante - C. K. Cooper & Co
Good afternoon. I just had a question about your production costs.
In the first quarter, on a unit basis, it was over $2 and you are guiding for the $1.60 to $1.80 range. Is it the production increase that’s going to get us there?
Steven Williams
The way that our costs for our partnerships are on our income statement, we include the cost of operations from partnerships wells in the well operations and pipeline cost line.
Joel Musante - C. K. Cooper & Co
Okay.
Steven Williams
And what we’ve done in the model is separate that out. That’s about $6.5 million for the year, so call it $1.5 million for the quarter.
I think if you separate that out, you will come closer to that number, which is still higher than that number, but it’s a lot closer. What we’ll do with the next model we’ll move that to sort of a net presentation in the model to make it a little bit easier to sort out.
But we think we should be closer to that, but then your partnership operations line, is going to be a net more like $2 million instead of $8.5 million.
Joel Musante - C. K. Cooper & Co
Okay. Just a quick question about the hedge volumes.
Do they include partnerships or do they exclude partnerships?
Steven Williams
On the graph here you are talking about where it shows the…
Joel Musante - C. K. Cooper & Co
Yes, and the 10-Q.
Steven Williams
Whenever we do a hedge position like in our press releases, they are net positions for the company.
Joel Musante - C. K. Cooper & Co
Okay.
Steven Williams
Looking at in this one there is one of the graphs that Rick had where he shows the forward hedge production of 40 Bcf for 2007 and 48 for 2008, those are actually the total positions in place as of the end of the first quarter of 2008; for example, were 48 Bcf equivalents. But that included hedges for 2008, 2009, 2010, 2011 and a little bit of 2012.
Those are the total hedge positions, which might be a little confusing because it looks like we are more than 100% hedged; in fact, they are just PET’s hedge positions. That’s on slide 18 of this presentation.
Joel Musante - C. K. Cooper & Co
All right. Thanks.
Operator
We have a follow-up question from David Tameron - Wachovia.
David Tameron - Wachovia
What commodity deck are you assuming for 2008?
Steven Williams
We used the strip as of the end of May…
David Tameron - Wachovia
You did? Okay.
I will go back and take a look at that.
Steven Williams
I don’t have the number right here, but if you need it, we can get it for you.
David Tameron - Wachovia
What I am getting at is what are you assuming for Rockies differentials for the remainder of the year?
Richard McCullough
We saw it widening.
Steven Williams
We are using a little bit wider one as we go. Do we have some forwards on Rockies also or are we just using the basis differential?
Richard McCullough
No. We are using the forward curve.
David Tameron - Wachovia
Okay. I will look at the forward curve.
Thanks.
Steven Williams
It does look like it opens up a little bit as the year goes forward though. I think it got as high as maybe 22% or so.
And it’s in the range of 20%. Basis differential.
Richard McCullough
Seems like it’s widening out, David, when it gets up above $10 a unit.
Steven Williams
The NYMEX gets above $10 and it looks like it gets a little bit wider on a percentage basis.
David Tameron - Wachovia
All right. And on your hedge position, how much more room do you have where you are at versus your debt covenants?
Any room to hedge more? Are you happy where you are at?
Steven Williams
We do have room to hedge more. Our corporate hedging policy is max 80%.
I don’t believe we have any limitations within the debt instruments at all. From that standpoint, we have complete flexibility.
But our derivative policy is the max 80%.
David Tameron - Wachovia
All right. And then one more question.
Marcellus, when you mentioned in the detailed evaluation or technical evaluation going on, what are you evaluating in the program and any update on your net acreage position?
Steven Williams
I think I have said earlier, we are currently estimating we have about 35,000 acres of where we own the rights in the Marcellus within the Marcellus fairway. What our guys are doing is looking at whatever is available from a geological standpoint and log standpoint.
We have a number of shallower wells drilled. I think we will likely take some of them and drill them on down into the Marcellus; science projects more or less.
But if we find something, then they could be profitable science projects; that would be nice. That’s the situation we are at is one assessing whatever information is available out there to try and determine where the best place is for us to go and determining where we have contiguous acreage blocks where it would make sense and seeing what the intersection of those two areas is.
David Tameron - Wachovia
Okay. Steve, are you aware of any people drilling around you off that acreage who have had success or not had success?
Steven Williams
I can’t say directly. Like on our Pennsylvania acreage, which is within the areas that Range for example is drilling; there are people actively considering drilling wells down in West Virginia within our areas of operation.
Clearly, we are going to have some acreage that falls within areas that’s going to be interesting for Marcellus. What we want to try and do is to find a little more before we go spend money drilling holes.
David Tameron - Wachovia
All right. Thanks.
Operator
Our next question comes from Phil McPherson - Global Hunter Securities.
Phil McPherson - Global Hunter Securities
Congratulations on a good quarter. Can you talk about the NECO dry holes and where they were in your acreage?
Were you trying to do step outs and trying to expand the play or were they just something weird you encountered in field?
Steven Williams
We are trying to expand the field. Most of our drilling to this point has been in Colorado and is where the bulk of the active development is in.
We have a fair amount of acreage across the border in Kansas. We’ve run some 3-D seismic across there and we are looking to try and expand the area that we have available to develop there, and some of those have been in that area.
Phil McPherson - Global Hunter Securities
So these two wells were in the Kansas area or close to it?
Steven Williams
Let’s say at least new areas; they are not direct offsets to existing wells that we are doing or obviously would be exploratory. We are trying to push out into the new areas.
Notwithstanding that, we’ve drilled I believe 26 wells that included a number of the ones that were in the new areas. So we are having a little bit higher dry holes because we are pushing the boundaries more, but we are still having good results and good success.
Phil McPherson - Global Hunter Securities
Right. And you said you had seven in various stages.
Are these in the same area that you are talking about?
Steven Williams
The same general area. There are ones that we drilled that we didn’t throw away immediately.
An exploratory well until it’s completed is considered to be in that sort of gray land.
Phil McPherson - Global Hunter Securities
Sure.
Steven Williams
So you keep them on your books as neither successful nor unsuccessful. They are basically wells that we classified as exploratory that have not yet been completed.
Phil McPherson - Global Hunter Securities
Okay. And when you talk about the total exploratory expense, and there are some leasing, and when you declare a dry hole on, call it a 60 acre lease then, are you then contributing the money you paid for those leases into the exploratory cost also?
Steven Williams
Yes. Some part of the lease cost would have to go into the exploratory cost.
Phil McPherson - Global Hunter Securities
Okay.
Steven Williams
If it was a 10,000 acre lease, it might not be the whole cost of the 10,000 acre lease, but it would be some part.
Phil McPherson - Global Hunter Securities
Section of it would be condemned basically.
Steven Williams
Yes.
Phil McPherson - Global Hunter Securities
Got you. And then can you talk about the two Barnett wells?
Were these vertical or horizontal?
Steven Williams
Both horizontal.
Phil McPherson - Global Hunter Securities
How long of a horizontal leg did you do?
Steven Williams
4,000 to 5,000 feet.
Phil McPherson - Global Hunter Securities
Okay. And have you fraced them yet or is that the next phase?
Steven Williams
That’s the next phase. We’ve been waiting for the gathering system to get to it, and basically we want to be able to complete the wells and put them immediately into production to minimize the amount of time the water is sitting on them.
Phil McPherson - Global Hunter Securities
Sure, that makes sense. And you think that once you complete these and hook them up you’ll have a type of an operations update specifically on that?
Steven Williams
We are going to have enough time to get a sense of what they are going to do. But we will provide an update.
You know what? We don’t like to sit on good news, Phil.
Phil McPherson - Global Hunter Securities
All right. And you sold your Bakken acreage a couple of quarters ago.
Did you retain anything up there with all the news that’s going on in Bakken?
Steven Williams
We still have some interest up in North Dakota. It’s more in prospective for some of the shallower formations of the Bakken, although there could potentially be Bakken results.
We sold our Bakken interest; we made a good decision to take the money and focus somewhere else.
Phil McPherson - Global Hunter Securities
Okay. And when you are talking about the Marcellus Shale and maybe potentially drilling down to it, at what depth are you thinking it is at in relation to the current wells that you are drilling there?
And is it like a $1 million kind of science experiment or is it more than that?
Steven Williams
We are looking at maybe 1,500 feet deeper than the existing wells. If you were drilling horizontal wells, the well cost might be over $1 million.
But I would be very surprised if it was that much to drill vertical wells.
Phil McPherson - Global Hunter Securities
You will probably just do a vertical to see what’s there and then, as you gain that knowledge, you can develop a full game plan kind of thing?
Steven Williams
This is going to be a sort of play it by ear kind of deal. And depending on how much information you have in an area and what kind of results you see, you could potentially log it I suppose and come back and decide you want to go back and drill it horizontal.
But I think likely initially, we’ll drill some of them vertically and then decide what to do after that.
Phil McPherson - Global Hunter Securities
Great. And then I just had one last question for Rick: you mentioned that the G&A number was going up $6 million from your guidance.
I don’t remember what the original guidance was. So can you give me the hard number?
Richard McCullough
We had initially put guidance out at $30 million. We revised it to $36 million.
Phil McPherson - Global Hunter Securities
Okay. And then given all the one-time charges, you would expect 2009 to be in line or lower than that?
Richard McCullough
I actually hope it will be lower than that, Phil, because we completed the Bolo accounting system and just put that in the first quarter of 2008. So we have incurred some charges there.
So I think actually, it will begin trending down.
Phil McPherson - Global Hunter Securities
Great. And is there a portion of it that’s non-cash based on stock compensation still?
Richard McCullough
Yes, parts of it would be non-cash.
Steven Williams
Yes.
Phil McPherson - Global Hunter Securities
Can you give us a rough number or percentage or something?
Steven Williams
I don’t know. If I had to make a guess, I’d say about half maybe.
Richard McCullough
Half the $6 million.
Phil McPherson - Global Hunter Securities
Okay. So maybe $3 million for the full year, something like that?
Steven Williams
We’ve got the $3.2 million in the first quarter. There might be let’s say maybe another $1 million in cash for the rest of the year.
Phil McPherson - Global Hunter Securities
Great. I appreciate the time.
Operator
There are no further questions in queue at this time. I would like to turn the floor back over to management for closing comments.
Steven Williams
I’d like to thank everyone for taking the time to join our call today and we will go back to work and see if we can make some more money for our shareholders. Thanks for joining us.
Good day.
Operator
Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time.
Thank you for your participation.