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Parallel Petroleum Corporation Q2 2008 Earnings Call Transcript

August 16, 2008 | about: PLLL

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Parallel Petroleum Corporation (PLLL)

Q2 2008 Earnings Call Transcript

August 5, 2008 2:00 pm ET

Executives

Cindy Thomason – Manager, IR

Larry Oldham – President and CEO

Donald Tiffin – COO

Analysts

Leo Mariani – RBC Capital Markets

David Heikkinen – Tudor Pickering

Gary Nuschler – Jefferies & Company

Neil Gore [ph]

Joe Dryden [ph]

Evan Templeton – Jefferies

George Whiteside – SWS Financial

Presentation

Operator

Good day ladies and gentlemen and welcome to the second quarter 2008 Parallel Petroleum Corporation’s earnings conference call. My name is Katie and I’ll be your coordinator for today. At this time, all participants will be in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) I will like to now turn the call over to your host for today Ms. Cindy Thomason, Manager of Investor Relations. Ma’am you may proceed.

Cindy Thomason

Thank you, good afternoon and welcome to our second quarter earnings and operations conference call. As we have done for our last several webcasts our slide presentation will be presenter-controlled today for all listeners whether by webcast or by telephone and you have access to that slide presentation at our website www.plll.com.

Larry Oldham, our President and CEO; and Don Tiffin, our Chief Operating Officer, will be our presenters today. Also joining us are Steve Foster, Chief Financial Officer; Eric Bayley, Vice President of Engineering; and John Rutherford, Vice President of Land.

Before Mr. Oldham begins the presentation, I would like to caution you that some statements contained in this presentation are forward-looking. You can identify forward-looking statements by the use of terminology such as “may,” “will,” “expect,” “intend,” “anticipate,” “estimate,” and other similar words. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable; however, we cannot give any assurance that our expectations will prove to be correct or that we will be able to take any actions that are presently planned.

All of these statements involve assumptions of future events and risks and uncertainties. As we all know, actual results may differ materially from those projected or implied. We caution you against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

Larry Oldham is our first speaker today; Mr. Oldham.

Larry Oldham

Good afternoon and welcome to our earnings operations update, thank you for joining us. If we take a look at our snapshot, let’s move the slide 3. We entered ’08 with momentum; one of our stated goals for ’08 is to increase the company’s average value production. Today we are happy to report that during the second quarter of ’08 our average daily production was 716 BOE per day which is a 2% increase compared to 7592 per day in the first quarter of ’08 and a 28% increase over the second quarter of last year.

Another one of our stated goals for ’08 is to increase the company’s proved developed produce and reserves. At June 30, the company’s PDP reserves were $24.3 million BOE which represented a 19% increase over the year end. This increase was a result of $5.2 million BOEs of additions last production run off of approximately 1.4 million barrels. As of June the company’s total proved reserves increased to $43.8 million BOE, which was a 15% increase over year end ’07. The 15% is a result of $7.2 million BOE of additions last production run off of approximately $1.4 million BOE.

The standardized measure of discounted future net cash flows as of June 30, 08 increased approximately 88% to $1.2 billion compared to year end of approximately $634 million. This 88% increase is primarily due to the previous mentioned reserve additions in all categories and increased oil and gas prices. We anticipate that the company’s F&D cost in ’08 will be closer to our current DD&A rate for BOE of approximately $15 per BOE. Don Tiffin will review the reserves later in this presentation.

Also as of June 30, we had 33 wells that were work-in-progress of which 21 were in Barnett, 5 in New Mexico and 7 in the Permian Basin. We have revised our ’08 capital budget to $171.6 million, that’s allocated $28.4 million to the Permian Basin, $74 million to the Barnett and $64.2 million to New Mexico.

Moving to the capitalization table on the next slide as you see we have about $41.5 million share outstanding; the company also as $150 million senior note that we issued in July of ’07 that has a seven year term with a 10.25% coupon. Our revolver as of June 30 was $230 million, we had $137 million outstanding that gives us $93 million of availability we do expect that revolver to be increased based on our mid year reserved numbers.

Our debt ratios as of June 30, we were 34% of market cap, 26% of enterprise value, the numbers that we really focused on is the per BOE numbers and that’s $6.55 per proved BOE and $11.81 of debt per proved developed producing BOE. As you can see the company is in the strong financial situation.

As we move to slide five we’re focused in three areas and we have a very diversified proved reserve base based on June reserves. No well has more than 1.5% of proved value, 55% of our reserves are in the proved developed producing category, 67% of our reserves in crude oil and 66% of our production as of the second quarter is natural gas. We have a lot of unbooked reserves associated with the Barnett Shale in New Mexico, Horizontal projects and our Permian Basin oil projects.

Slide six, this is basically a photo of our four straight compression facility in downtown in Fort Worth as you look to the West, Chesapeake continues to install additional compression pipeline and our two AMIs that we have with Chesapeake.

Moving to slide seven, second quarter compared to the second quarter ’07 you can see oil and gas revenue were up 105% to $56.1 million which is a record for the company, operating costs were up 36% to $24 million, operating income was up 165% to $32 million. We incurred a net loss of $29.2 million. That loss includes a pre tax loss of $71.6 million on derivatives which included settlements of $14.6 million. Net cash provided by operations was up 169% to $45.4 million compared to $16.9 million to the prior year.

Moving to slide eight and looking at the balance sheet; as we previously stated ’07 was a transition year both financially and operationally for the company. Again in July of ’07 we issued $150 million senior note which we paid down our term note of $50 million and applied the balance to our revolver. In December of ’07 we issued $3 million shares of stock and raised $52.5 million which we applied to the revolving facility pending its use for exportation and producing property activities.

At June 30 ’08 we had $93 million available on our $230 million credit facility derivative and put obligations increased approximately $50.8 million because of increased oil and gas prices as of June 30. As you can see our balance sheet is very strong and it is the strongest in the company’s history.

Moving forward to slide nine, net cash provided by operating activities increased to 104% to $70.9 million compared to $34.7 million in ’07. Net cash used in investing activities increased to 83% to $148 million compared to $81 million in ’07 and our net cash provided by financing activities increased 71% to $78 million compared to $45 million.

Moving to slide 10; ’02, we look at our historical production. This graph basically shows that we have a 31% compounded annual growth rate in Parallels net production from ’02 through the second quarter of ’08. The graph also shows the relative volumetric contribution from each of Parallel project areas and the growing importance of the Barnett Shale and The New Mexico Wolfcamp components and we believe as we use the Permian Basin in the forward quarters, you will see how important the growth is in the Permian Basin as well. Don Tiffin will review each of the company’s major assets later in this presentation.

Moving to slide 11; basically this slide is the back up to the previous slide that you can see that the nice growth we’ve had over the last five quarters and then if we’ll move to slide 12, this is the detailed information supporting that graph and we are one of the few companies that details the production by property and by area and as you can see our total volumes were 7700, 16 BOE a day which was up 28% over the prior year and we had a nice increase in the gas and the resource projects and the Permian decrease however we expect that to increase as we move forward in the third quarter and quarters beyond.

Another question that we get a lot about is the oil derivatives, if we can go to the next slide, which is slide 13, I believe. It will be the capital budget; our capital budget as you can say we’ve increased it to $171.6 million. This budget will cover 121 gross wells and 67 workovers and conversions. As you can see, the resource projects will get $138.2 million of the budget, which is 81%. The Permian Basin will get $28.4 million, which is 17% of our budget and as you can see the Permian represented 36% of our second quarter volumes and it represents 72% of our total proved reserves as of the end of June 30.

Moving to slide 14, we’ll discuss our oil derivatives; as you can see our second quarter of ’08 oil production was 2606 actual barrels of oil per day. For the balance of ’08 we have approximately 2150 barrels of oil per day hedge, which is about 83% of current volumes and you’ll notice that in that ’08 hedged column that we have a ugly swap at 1,200 barrels at day at $33.37 of barrel, that goes away January 1,’09 which will change our outflow as far as payment on derivatives and you can see in ’09 and ’10 and ’11 the volumes that we have puts associated with and collars and our game plan in the future will be basically what we’ve done recently; we intend to buy floors in lieu of putting on any collars or swaps.

We can move to the next slide; the same slide related to gas derivatives. Our gas rate in the second quarter of ’08 was about $31 million a day. We have about $10 million of that hedged in the second half utilizing the collars. In calendar ’09 we have about $9 million a day hedge, which is less than 30% of our current volumes and we expect future positions will involve the purchase of puts, whereby the company keeps all of the upside.

At this time Don Tiffin will review the company’s operations, reserves and major properties with you; Don.

Donald Tiffin

Okay, thank you Larry. Slides 16, is just a transition slide showing the compression facility on the Hudson Pad in Downtown Fort Worth. It’s a very good picture that just kind of shows you the environment that we are working in over there.

Moving to slide 17, you will see our now familiar areas of operations. Today I’m going to limit my comments to the two gas resource plays, the Barnett Shale, the New Mexico Wolfcamp both horizontal plays. I’ll also talk a little bit about the Permian oil development and specifically the Carm-Ann, Harris, the Diamond M Deep or Canyon Reef and the Fullerton assets.

Moving to slide 18 and Larry has already pointed this out, but we’re very, very proud of the 41% annual growth rate that we have had in proven reserves since 2001. That growth rate has come through a combination of acquisition, leasing activity and then drilling activity on both acquired assets and leasehold assets.

As you can see with the exception of midyear ’07 we’ve shown very consistent growth. The 0.5 million barrel reduction at midyear ’07 or which actually shows between a years end ’06 and ’07 was a change in the methodology in which we book horizontal PUD locations. That was a one time correction or change and now we are consistent whether we report that and again we’re showing good growth, good results.

Moving to slide 19, just give you a little better feel for the distribution on proven reserves. Looking at the pie chart up on the upper left hand corner again you can see that as of June 30 we stood at 43.8 million barrels and that split out between PDP, PDNP and PUD at 55%, 2% and 43% respectively and that’s in terms of volume.

On a value basis, you can see in the pie chart to the right of that we are at 57% PDP, 4% PDNP and 39% PUD and this is looking at a standardized measure of $1.2 billion for the reserve base. If there are some of you that are not familiar with that standardized measures basically the PV-10 is adjusted for future tax liability.

Looking down at the bottom of the slide, in terms of geography, the two resource plays now combined to make about 27% of our reserve volume. As you can see the Gulf Coast continues to fade away, that is by design and then the Permian currently stands at 72% and then in terms of product mix, 67% oil, 33% gas, but consistently growing gas volumes as we move forward with development in both the Barnett and the New Mexico Wolfcamp.

Moving to slide 20 and to provide a little bit more breakdown by geography, the green area on the left hand slide you can see is the Permian basis oil volumes which is we’ve already said represent about 72% of our reserve volume and that is broken down by 50% PDP, 3% PDNP and 47% PUD. You will see the footnote tied to the PUDs which show 179 PUD locations, those are all infield drilling locations. We also have included in that those PUD reserves, water flood response that would be anticipated at Harris, Carm-Ann and Diamond M Shallow.

To the right hand side you will see the distribution on the gas resource plays and again as we said 27% of our reserve volume broken out with 68% PDP and PUD and that’s an obvious disconnect between the booked reserves, the proven value in the company and the total potential. If you look at the text box below the pie chare you will see that currently we have 15 PUD locations in the Barnett and 22 PUD locations in the Wolfcamp. I’ll elaborate on that in a just a bit, but we can say that that really barely scrapes surface in terms of potential locations that we have to drill in both of those resource plays.

Moving to slide 21 we’ll talk a little bit about work-in-progress. With a $170 million capital budget work-in-progress is always a moving target there is always work-in-progress, but particularly in the areas where we have continuous drilling program such as the Barnett and the New Mexico Wolfcamp you will see very little change quarter-over-quarter in this amount of working progress or free production of work, but working down through the chart you will see that as of the end of June we had 21 gross wells either drilling completing or awaiting completion or shut down and awaiting pipeline in the Barnett; you can see the breakdown for yourself there.

In New Mexico we had five wells either drilling completing or awaiting completion and then in the Permian side you can see that there was a total of seven wells. So, work-in-progress on the total of 33 wells or 15 wells net has a significant importance and we’ll point back to it again a little bit later as the Barnett. Out of the 21 total wells that we had work-in-progress on them you will see that 18 of those were in pre production status with the wells drilled, but yet to be either completed or replaced on production.

The Next slide is again just another snapshot of a different compression facility in Fort Worth and we will move forward to slide 23 at this point. The Barnett, we continue to pick up leasehold there as you can see on the chart we picked up to-date 31,600 gross or 9,300 net total acres and I mentioned the disconnect between potential locations. If we just assumed 50 acre development in a 100% acreage utility just for east math you will see that we’ve got an excess of 600 theoretical drilling locations there in the Barnett and again continue to pick up leasehold.

Of that 31,600 acres, about 10,300 of that is the area that we referred to the as the Halo and this is developed area surrounding the flood plain. At this point considering about 26,000 total or potential acres in the Halo we’re about 40% leased, so we are making progress in getting that Halo acreage picked up and as we’ve said before that Halo acreage is controlled by strategically located drilling pads within that developed area.

As you can see moving down the chart, production growth has been good, a little bit lumpy; we’ve talked about that in the past and I’ll elaborate on that in the next page. We had 51% production growth from the fourth quarter of ’07 to the first quarter of ’08. We are down slightly from the first quarter to the second quarter, but again that is a pattern that we’ve seen in the past and I will again explain that. Today we have 78 active Barnett wells and as I said just a few moments ago 18 wells in preproduction mode.

One of the highlights in the Barnett has been rapid reserve growth at year end ’07. We had about 3 million barrels equivalent booked to the Barnett and mid-year a late 4.3 million barrels for 43% increase, so good reserve growth there. From a capital budget standpoint we expect to drill 53 wells in the Barnett and meeting with operators were pretty well on track and just finish up the year right in that neighborhood.

Now moving slide 24, I’ll explain, what we’ve talk about when we say the lumpiness and this is an issue that it’s really inhere to pad development, this is we’re dealing with topography that requires multi-well pads, as long as we have a drilling rig on that pad or completion activity on that pad. You’re basically, limited to one well activity at the time and just as an example, if you have a pad for your drill four wells back-to-back, you have to get the drilling rig out of the way after that fourth well is drilled before you can ever start moving into just complete that first well and again this is why we have such lumpiness.

If we look down at the yellow graph, we will see this, now familiar pattern of rapid rises, it’s in a plateau or in the case of this past quarter maybe even the slight drop that 1% and then this shows wells get brought back on production, those new wells connected and brought on production and you will see a nice rise in production and we still expect that this will be the pattern that is going to repeat itself in this area for the foreseeable future.

Now, let’s about New Mexico just a bit. If we’ll go to slide 26, we can see the trend map here in New Mexico. We’ve talked about this quite a bit, there is roughly 300,000 acres in that dotted area and basically Parallel divides this area up into three sections. We have, what we called the Northern area, the Southern area and the Central area, most of our ownership is concentrated in the Northern and Southern areas, most of our drilling activity for this year has been concentrated in the Northern area.

Where we have one rig continuously drilling and have had there since late last year. We do expect to moving on a second rig during fourth quarter of this year that rig will be assisting and taking a wells placing down from 320 acres to 160 acres. In New Mexico, when this trend, a well will hold 320 acres, so we’ve been tying up leasehold with this early drilling. We’ll continuing to do that, we still have a number of 320 acres units to get drilled and held, but with one rig continuing to do that we’ll take a second rig and start knocking out those 160 acre in field.

On the Southern end, we’ve been acquiring processing and now interpreting 3-D and as we said in the past, we’re looking four areas on natural fracturing where we can expect better than average well results. As we move forward into the fourth quarter, we do expect the drilling on the Southern end again in some of these areas that appeared to be more naturally fractured and in the immediate situation with rigs there as well we’ll move that second rig, out of the Northern area to drill in the Southern area on an as needed basis.

Now, moving to slide number 27, we’ll talk just little bit about overview of overall leasing activity and this trend has slowed, and that’s basically just due to the fact that most of the acreages either held by a production or leased up at this point. We have again talking some renewals particularly in the areas that we are especially interested in. Without a doubt, Parallel is now most active player in this trend and probably the most significant player in terms of well performance and just overall capital expenditures.

You’ll see a little bit about the breakdown between areas and Northern area we have 53,000 gross acres under lease. We’ve recently announced an acquisition of some partners in that area, which takes our net to about 53,000 acres, so we’ve get very good concentration of ownership there. As I’ve just mentioned, we’re moving on into 160 acre development in addition to continuing to hold the 320s and we do expect that to continue during began in the fourth quarter of the second rig coming in.

The Central area as much less important to us in terms of overall impacts primarily partner operated, primarily EOG relatively limited activity going on in that area and then finally the Southern area have our second largest acreage concentration at about 41,000 acres gross, 26,000 acres net and as I mentioned we’ve been acquiring 3-D, processing 3-D and now interpreting that 3-D data and do expect to have some drilling activity in the fourth quarter and some of these high graded areas.

Moving over the slide 28 we’ve seen a nice production growth quarter-over-quarter beginning in the fourth quarter of ’07 actually beginning before that. We currently have about 50 wells on production; we’ve also had very nice reserve growth. At year-end ’07 we had 4 million barrels equivalent booked in New Mexico and at mid-year we have 7.5 million barrels equivalent booked for about an 88% increase. We do expect to drill roughly 27 wells there this year we spend a little over $60 million as you can say on the graph and again we are on track to make that all that happen.

Moving to slide 29 the lumpiness that we saw in the Barnett production part is really not inherent to the New Mexico and reason being we are not they are drilling on the pads. We typically put one well on each pad one going to, excuse me two wells on each pads and those wells going in opposite directions. This allows us to save money have a smaller environmental foot print and just really be more efficient in our drilling operations.

The fact that it only takes roughly three weeks to drill one of these wells also minimize that delay between getting well drill and getting the well booked in own production, but you can see we have really solid growth with and particularly I’d like to point out the one rig development, we moved to one rig in the Northern area in the third quarter of ’07 you can see that’s one of the safer portions of the curve.

We recently move the rig up to the Northern end because of the variability that we are having in well reserves on the Southern area. We were very confident that we have much more repeatability on the Northern end we have made a decision to do that, to move that one rig up there, while we’re receiving 3D on the Southern end and as you can see since we’ve done that over the last three quarters. We’ve had about a 60% increase on daily volume metric production and then the one thing again – I want to add one more time is that beginning in the fourth quarter we will start 160 acre infill drilling.

The infrastructure on slide 30, is basically in place we do continually expand particularly the Hagerman Gas Gathering System the way we laid our development out on the Northern end, its basically in one mile quarters where we will have again a top line running down to section line with those wells surface locations those wells drilled along the section line with one will move drill to the east, one drill well drill to the vast, until we will move over 2 miles and lay another pipeline quarter and begin developing that quarter and that’s kind of the birds eye view for that development activity it looks like at this point.

We go ahead and transition at this time and start talking about the Permian Basin activity and we will go to slide 32 one of the things if you look at the top of the slide you will see that on average Parallel operates these property at 85% working interest and about 71% net revenue interest, that’s really one of the key ingredients that we believe is critical to success and that’s you have to have impact full ownership and you have to have control on the development timing and the technology being used in that developments.

So, all of the assets as you see in our portfolio with the exception of very few, we do exercise that degree of control. As you can see we’ve got a lot of acreage. Most of the property is immaterial and either as immaterial water flood or we’ve yet to initiate water flood and of course treasury behind that. None of the things that’s consistent with properties as we have solid production we have lots running room and as you can see over the past three quarters we have very stable production.

During the time period between the fourth quarter of ’07 and the second quarter of ’08, which we are essentially not developing at all during that time period. We’ve had about a 7% decline. So, even in the absence of continues development, we have very stable, very flat decline rates.

In terms of reserves the Permian all with the exception of some of the unproven oil at Diamond M as primarily booked at this point at year-end ’07 we have 30.4 million barrels booked at mid-year ’08, 31.5 million barrels or about a 4% increase. As we continue to prove up opportunity particularly at Diamond M Deep and some of the step by out acreage at Harris will be adding reserves there, but as you can see as I have already said a lot of running room with 179 PUD locations at this point, and then plus waterflood reverses on top of that.

The Permian really does not consume a lot of capital relative to the total company about $28.4 million will be spent during this year, and with that money we’ll drill 34 wells and do about 67 workovers. About a 110 total well operations and we are on track they’re also.

Slide 33, shows the relative contribution just from a graphical or pictorial standpoint just kind of give you the feel for what truly is important. Fullerton is by far and away the largest volume metric contribution at this point, still the largest reserve volumes of any project area that we have and it is just very important to the company, and providing stability and cash flow, and I’ll elaborate on that also in just a few moments. Now, let’s talk about Diamond M just a bit this is on slide 34. There are two projects actually at Diamond M, we have the major project which is the Canyon Reef and then we have a minor project which is the Diamond M Shallow, which are as production from zones above the Canyon Reef.

As we’ve recently announced, we made an acquisition through the exercise of a pref right at Diamond M, and we’ve began the development of Diamond M this year, we have budgeted six wells for the first portion of the year, we got six wells to drill during the fourth quarter, but through the acquisition and through these first six wells, and one workover that we’ve done in February, we’ve taken production on a net basis, we’ve taken production from about 183 from the Canyon Reef during the first quarter to 665. So, almost a 500 barrel equivalent increase on a net basis during that timeframe or about a 260% increase, so we’ve had really good volume metric growth, particularly on the net basis and again that’s a combination of the acquisition and the developments.

In terms of reserve bookings, we had 2.4 million barrels book to the Deep and year end ’07, we now have 4.2 million barrels that’s a 75% increase, and that’s primarily the result of the acquisition that was made. It seems a little bit out of sync, but I’ll explain why you get such a nice net bump period on the following slide.

Diamond M Shallow as I’ve said is the lesser project, we will spend a little bit of money there mainly to work on our injection site. At year end ’07, we had 1.9 million barrels of reserve book there, at mid-year we have 1.9 million also we did pickup interest through the acquisition on the Shallow, but at the same time we’ve also taken just a small downward performance revision on the some the of Deep drill or some of the Shallow drilling that we have planned there.

Now moving slide 35, we’ll talk a little bit about production response. First thing I would like to point out is down at the bottom of the graph, you see the Green Wedge label based production. Prior to the exercise of the pref right at Diamond M, that base production was owned 100% by Southwestern Energy. We shared in volumes above the base of the yellow developmental reserves, but through the acquisition, through the exercise of that pref right, we’ve picked up our proportionate share of that base production about 88% on a working interest basis about 76% on net basis. So, that those are net reserves that we were producing from a gross standpoint before that never had ownership and until after the acquisition.

The yellow area would be the development area above the base, and as you can see it peaked in June ’06 at somewhere between 900 and 1,000 BOE per day on a gross basis, and since that time, we’ve had several faces of development, which is different workover activity, and looked at the drilling, you will see some production specks along in there, you also see a relatively short declined for instance between March of ’06 and March of ’07, and this is due to the unsupported nature of this asset.

The development as we’ve said in the past is infill drilling, as waterflood implementation or actually reimplementation. It’s well deepening, its workover just reactivations, but the main issue is to give waterflood support, and then ultimately CO2 waterflood support back end of the area, – where we don’t have this harsh declines.

Moving over to the right hand side of the column, you will see the last data point that we have right there is about 700 BOE per day on a gross basis. I think as I already pointed out we’ve had one workover, we’ve drilled six wells in the most recent and the last well of those first six to be completed and placed on production was just happen in this past week end. I can tell you that today’s production is about 900 BOE per day on the gross basis. So if you look back to the left across that curve you will see that we are at the highest point since we’ve made the acquisition with the exception of that one peak in ’06.

Carm-Ann the next property that we will talk about, Carm-Ann was acquired in 2004 late in the year. It’s the San Andres property at about 4900 feet in depth and we’re primarily interested in the property because within opportunity to reduce spacing from 40 acres per well, down to 20 acres per well and ultimately 10 acres per well. The property was also in primary depletion so we have the opportunity for water flood implementation and then ultimately CO2 along with stimulation of existing wells.

Our reserves at mid year for Carm-Ann stood at $6.9 million of barrels at year end of ’07 there were – I don’t have a number in our notes but we’ve had good increase there also. We drilled five wells this year and we’re just now placing those first wells on production actually that first well on production. Today we’re through ’08 we will spent about $3 million there and again we have to drill those five wells and move forward on water flood implementation where we expect first injection sometime probably in the first quarter of next year.

The production plot that you see for the Carm-Ann on page 37 show some very nice peaks that also again that very a harsh decline coming off as unsupported primary production. So our number one goal and objective here Carm-Ann is to get the curves supported with the water flood in place and move – and to do that we are moving forward the unitization again as I’ve already stated we will begin injection sometime in the first quarter of ’09.

The Harris field is the property or the set of properties immediately to the west of Carm-Ann it was acquired basically year after we acquired Carm-Ann for all the same reasons being able to take the wells spacing down from 40 acres to ultimately 10 acres spacing water flood implementation CO2 secondary, tertiary the were basically everything that we had planned and expect to see in Carm-Ann we have also happening at Harris. This year we will drill 10 wells those 10 wells have were finishing up the drilling on those right now we have placed six or seven of those wells on production and it will move to the production response curve on page 39.

If you again move just to the right of that last data point and stick a dot (inaudible) about 900 BOE per day that’s where we are seven wells out of 10 on production at this point. So again good response from the drilling program there and with three wells still left to place on production. The final property that I will talk about is Fullerton. This is the first property that we acquired after changing the business plan in ’02 as we acquired in late 2002 and has really performed just magnificently again it’s a San Andres property.

The water flood was put in place in 1996 so there has been relatively small amount of development capital required for this property. Yes the property is still is our largest contributor for free cash flow it currently represents about 21% of our total bookings, the property was acquired for $46 million at the time there were 9.2 million barrels booked to it. You can see our current bookings is 9.3 million barrels and the property is worth north of $400 million now. So again just a fantastic property and has exceeded all expectations. We do expect to drill seven wells this year we expected those wells where we get started late in August.

Last slide that I will discuss is this next slide and this is the Fullerton production. First thing I need to draw your attention to is just the different scale on the left hand side the scale starts at 1500 goes up to 2500, but what I would really like to point out is just the stable nature of this curve.

If we look at the time period between September ’04 to the last dead point in June you will see a peak its just over 2400 barrels a day and you will a valley it’s just under 2000 barrels a day or there is about a 20% delta over a four year time period, very stable production again; those are two extreme peaks and valleys in the production plot.

If you look at just the last couple of years you will see peak at around 2200 barrels and then a valley again at just under 200 barrels, about a 10% variance over that two year time period and this is what we talk about when we are talking about stabilized water flood production. You’re looking at our annualized decline trends here or somewhere in the 4% to 5% exponential rate and this is the plan, this is what we intend to do at Diamond M Deep with implementation and expansion of the water flood there and with the implementation of the water flood at both Harris and Carm-Ann.

And with that we’ll conclude the presentation and open the floor for questions.

Question-and-Answer Session

Operator

(Operator instructions) your first question comes from the line of Leo Mariani from RBC; please proceed.

Leo Mariani – RBC Capital Markets

Just a question on the Wolfcamp here; you mentioned bringing a rig from the North area down to the South and start to drill a couple of wells there, could you maybe just give us a little color in terms of what you’re seeing. In prospectivity I know you folks shot some seismic out there and just give us a little more detail there.

Larry Oldham

Yes, Leo we completed several rounds of processing and the intention of the 3-D in the first place was to try to identify areas that appeared to be more extensively naturally fractured and we think we are seeing some of that.

We are continuing to work the data; we’ve got a little bit more fine tuning to do before we are really ready to go and just kind of a toe in the water approach on this new concept, this new theory, what we will do. Once we identify the areas, the first areas, the first couple of areas that we would like to travel, we’ll permit those wells and then we’ll pull that second rig or one of the two rigs at that time we’ll have running in the northern area down to just to come to the south and then drill. The first well or two to test out theory and see if the 3-D really did accomplished what we would have hoped.

One thing I will also add to is we believe that there is an opportunity if we could truly identify an area of extensive natural fracturing, that we could get by with drilling a vertical well and we would intend to do that to just come in, drill the vertical well, do the single stage completion in the Wolfcamp, see what those results are, set the wells geometry up or we could cut a window in the well and take the lateral out, but if we indeed could get good well performance with the vertical wells that would further enhance the economics on the Southern end.

Leo Mariani – RBC Capital Markets

Okay, just the question on the Barnett here. If I’m kind of reading some of the numbers right you guys put out, it looks like you brought on additional four net wells or so in the Barnett in the second quarter. However, I guess your production looks like it was down about 1% sequentially from the first quarter. I was just trying to kind of get my arms around kind of what went on there; maybe you had something to deal with – well timing are not below your wells and maybe it came on at very end at the second quarter there, you’re seeing more color on that?

Larry Oldham

They came out late in the second quarter Leo.

Leo Mariani – RBC Capital Markets

Okay, I guess how many wells, did you guys end up bringing on, in the second quarter.

Larry Oldham

Well, we had 21 working progress at the end of the second quarter, today we have 26 wells in progress. So, I don’t think we brought any new wells on during July since the end of June and during the second quarter our net wells increased, what two or three net wells for the quarter.

Leo Mariani – RBC Capital Markets

Yes and I think I had seen four somewhere in your press release there.

Larry Oldham

Yes, I think we just brought on a very few net wells. If you look at the graph the net well count of Barnett, it looks like four net wells, yes.

Leo Mariani – RBC Capital Markets

Okay and I guess that by this point in time you guys are not experiencing any kind of production restrictions or anything like that obviously there’s been some others in the industry that have talked about that during the quarter?

Larry Oldham

Yes, our takeaway capacity looks pretty good right now, Leo. Chesapeake’s done a really good job working that issue hard. They appeared to have ample blank capacity and it’s really more of an issue of wellhead connections and just getting wells hooked up in a timely manner and again that goes back to the pad issue.

Donald Tiffin

And then permitting on the top line, there’s quite a bit of condemnation going on, getting the pipelines built, the gathering system. That’s why you are going to see the lumpiness and the spikiness in that production profile that we’ve seen historically. We expect that to continue until they basically have that whole infrastructure in place.

Leo Mariani – RBC Capital Markets

Okay, thanks a lot of your time you guys.

Larry Oldham

Thank you.

Operator

(Operator instructions) your next question comes from the line of David Heikkinen from Tudor Pickering; please proceed.

David Heikkinen – Tudor Pickering

Hello, just thinking about when we toured through the Barnett, the number of locations and pads that you have, when would you have all of the gathering lines to each of those pads were then you’ll have the systems in and not have these lumpy developments?

Larry Oldham

Well, we have 75 pads and I believe to-date we’ve just spotted our 100 well. So, we probably have less than half of those pads, way less than half of those pads with wells drilled and if you visualize this on the map, our acreage starts at the Dallas County line on the east. It goes all the way to Downtown Fort Worth and then goes due west of Fort Worth about another 8 to 10 miles.

So, we are talking about 25 plus miles, right along the Trinity floodplain and our project started east of Downtown, which is almost not quite in the middle of our project and they now have almost, not quite to Dallas County servicing wells to the east and then we’ve got wells down at the GM plant, which I think we are on our sixth or seventh well right now and those wells will not be connected probably to the first quarter of ’09.

So, what Chesapeake is doing is they are curing leases so they are not going to lose any leasehold within this floodplain, because as you know this is one of the best areas in the entire Barnett Shale. So, regardless of whether we have pipe in place or not; we’re going to go ahead and drill. The pad to drill wells to get our acreage held and then they’ll bring the pipe to the – I mean it’s a progress, it’s a continual process.

So, there is really not a good answer as to when we think this things get lined up because we absolutely do not know. I think active producing pads today, I think we have an excessive producing of 20; active producing pads. We’ll probably have at least I’m going to speculate team that have been drilled, that are not producing in this stage of the game, but if you take a look Don mentioned 50 acres spacing, but I use 40 acres and then we do know that there are other operators out there today already experimenting and dropping things down to 20 acre spacing. They are drilling wells 250 feet apart, 3500 feet in length and they are applying a new fracture of stimulation to that.

I believe Quicksilver, just recently talked about their four new wells that they drilled 250 foot apart with improved stimulation, so as this is evolving you’re going to see more wells drilled in the existing pads that we have, new pads being developed and Chesapeake cannot get ahead of their land department, that’s why we have four rigs running.

So, I think it’s going to be quite well before you’ll see the lumpiness go away because we still have a lot of un-drilled pads yet to be drilled, that will get drilled, but drilling only 50 wells a year until they can get things cured up and accelerate that activity, I think you’re going to continue to see this lumpiness.

David Heikkinen – Tudor Pickering

Okay. The acquisition of the wells and pipeline in the Wolfcamp, how much reserves did you acquire with that and then can you remind us the reserves for the other property acquisition as well year-to-date?

Larry Oldham

I think the Diamond M was little over 3 million BOE reserves acquired and off the top of my head I don’t know the number of New Mexico. We didn’t disclose sue to confidentially with the private parties involved.