Parallel Petroleum Corporation Q3 2008 Earnings Call Transcript

Parallel Petroleum Corporation (PLLL)

Q3 2008 Earnings Call

November 4, 2008 2:00 pm ET

Executives

Cindy Thomason - Manager, Investor Relations

Larry Oldham - President and Chief Executive Officer

Donald Tiffin - Chief Operating Officer

Steve Foster - Chief Financial Officer

Eric Bayley - Vice President of Engineering

John Rutherford - Vice President of Land

Analysts

[Unidentified Analyst] - Jefferies

David Heikkinen - Tudor Pickering & Co.

Pavel Molchanov - Raymond James

Leo Mariani - RBC Capital Markets

David Snow - Energy Equities

Patrick Walker - Walker Smith Capital

[Neil Four] - Private Investor

Richard Tullis - Capital One Southcoast, Inc.

Presentation

Operator

Good day, ladies and gentlemen, and welcome to the third quarter 2008 Parallel Petroleum Corporation earnings conference call. My name is [Carmen] and I'll be your coordinator for today. (Operator Instructions)

I would now like to turn the presentation over to your host for today's call, Cindy Thomason, Manager of Investor Relations. Please proceed.

Cindy Thomason

Thank you. Good afternoon. Welcome to Parallel Petroleum third quarter 2008 earnings and operations conference call and webcast.

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. [Break in audio] webcast and telephone listeners have access to the 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 like 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 against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

Larry Oldham is our first speaker. Mr. Oldham?

Larry Oldham

Thank you, Cindy. And if we can go ahead and go past the financial slide - let's go to Slide 4  we'll start.

As of September 30 we had approximately 4.6 million of common shares outstanding.

The company also has $150 million senior note that was issued in July of '07. It has a seven-year term and it matures in 2014, and it carries a 10.25% coupon. Our revolving credit facility has a borrowing base of $230 million. As of September 30, we had $162.5 million outstanding, with $67.5 million available. In order to strengthen our liquidity and financial flexibility, we have recently drawn an additional $62.5 million under our revolving line of credit, bringing our total outstanding borrowings to approximately $225 million. The majority of the loan proceeds have been temporarily invested in a money market account.

As you can see, our banking group as of October 31 includes Citibank, BNP Paribas, Compass, Bank of Scotland, Texas Capital Bank, Western National Bank, and our two recent additions  Bank of America and West Texas National Bank.

Moving to Slide 5, third quarter compares to the third quarter of '07. Oil and gas revenues were up 91% to $56.2 million. Total operating costs and expenses were up 38% to $25 million. Operating income was up 176% to $31.2 million. Net income of $58.7 million includes a pre-tax gain of $65.7 million on derivatives. The company settled in cash a net payment of $13.5 million in derivative contracts during the period. Net cash provided by operations was up 123% to $37.5 million compared to $16.9 million for last year's third quarter.

For the nine months of '08 compared to nine months of '07, oil and gas revenues were up 95% to $156.2 million. Total operating costs and expenses were up 45% to $70.2 million. Operating income was up 172% to $86 million. As you can see, net income was $26.7 million. It also includes a pre-tax gain of $27.8 million on derivatives. The company settled in cash a net payment of $36.3 million in derivative contracts during this period. Net cash provided by operations was up 110% to $108.4 million compared to $54 million for the nine months of '07.

For the first time the company is providing non-GAAP financial measures of operating cash flow and adjusted EBITDA. Please refer to the company's earnings release or go to the company's website at www.PLLL.com for further explanation and reconciliation of the following measures:

For the three months ended 9/30/08 compared to 9/30/07, operating cash flow increased 164% to $38 million from $14.4 million. Adjusted EBITDA increased 133% to $42.6 million from $18.3 million.

For the nine-month period ended 9/30 compared to the prior year, operating cash flow increased 151% to $102.7 million from $40.9 million, and adjusted EBITDA increased 123% to $117 million from $52.6 million.

Again, we want to caution you that this is the first time that we have provided non-GAAP financial measures and please refer to our news release and our website for the reconciliation of these numbers.

If we can move to Page 6, our balance sheet, at September 30 current assets were $52.2 million, which included $10.7 million of cash and cash equivalents. Current liabilities were $81.6 million, including current derivatives and put premium obligations of $22 million. Long-term liabilities were $371.9 million, which includes $309 million of debt and $22.3 million of derivative and put premium obligations.

The borrowing base under the company's revolving credit facility was $230 million at September 30, and outstanding borrowings under the revolving credit facility at the same date were $162.5 million. In addition, the company had $150 million outstanding under its 10.25% senior notes. And as of September 30 the company's net capitalized costs associated with its oil and gas properties and other equipment were $656.9 million, with a stockholders equity of $265.1 million.

Moving to Slide 7, Statement of Cash Flows for the Nine Months Ended, net cash provided by operating activities increased 110% to $108.4 million compared to $51.5 million in '07. Net cash used in investing activities increased 72% to $209.3 million compared to $123 million. And net cash provided by financing activities increased 50% to $103.8 million compared to $69 million.

Moving to Slide 8, Selected Operating and Financial Metrics, for the three months ended September 30 of '08 compared to September 30 of '07, the average sales price per BOE was $74.45 compared to $49.62 in the prior year. Total operating expenses per BOE were $33.19 compared to $30.60. And operating income per BOE was $41.02 compared to $19.03. It is important to note that direct lease operating expenses were $9.99 per BOE compared to $10.84 per BOE in the prior quarter of last year.

Nine months ended 9/30 compared to last year, average sales price per BOE was $72.73 compared to $47.86. Total operating expenses per BOE were $32.70 compared to $28.93, and operating income per BOE was $40.03 compared to $18.93. I do want to refer you to the company's 10-Q that has the MD&A section and it talks about the operating metrics in detail by each category.

Moving to Page 9, we do have oil derivatives. Our actual daily oil production in the third quarter of '08 was 2,977 barrel a day. For the balance of '08 we have approximately 2,150 barrels of oil per day or 72% of our oil hedged, with an average floor price of $46.63. Please note that we have a swap for 1,200 barrel a day at $33.37 that goes away January 1.

In '09 we have 2,400 barrels or 81% of our third quarter oil production hedged with an average floor of $70 a barrel. In 2010, we have 2,100 barrels a day, which represents 71% of our third quarter oil production. It has an average floor of $71.10. In 2011, we have only 400 barrels a day hedged with a $100.00 floor.

Moving on to our gas derivatives, actual daily gas production in the third quarter of '08 was a little over 31 million a day. For the balance of '08 we have approximately 10 million a day or 32% hedged with an average floor of $7.38. For calendar '09 we have about 9 million a day or 29% of our third quarter gas volumes hedged, with an average floor of approximately $7.00.

The company's bank facility requires that the company have a minimum of 50% of its production hedged for the next 24-month period.

If we move to Slide 11, basically this shows the historical production growth from '02 through third quarter of '08. It shows we have a 30% compound annual growth rate in our net production generated. The graph also shows relative volume metric contributions from each of Parallel's project areas. During '09 we expect production growth will occur primarily in the company's Barnett Shale gas project and the company's Diamond M Canyon Reef oil project. Don Tiffin will review the company's major assets later in this presentation.

Moving to Slide 12, basically in graphical form you can see the company's net daily production for the third quarter ended September 30 averaged 8,205 equivalent barrels of oil per day, an increase of 6% when compared to an average of 7,716 barrels a day during the second quarter ended June 30 of '08.

Now let's move to the next slide and I'll give you just a few details. This slide on Page 13, we're talking about the average BOE per day. It provides analysts and investors with a high level of transparency since production is reported on each property for the current quarter compared to the prior four quarters.

As you can see, during the third quarter of '08, production from the company's Permian Basin oil projects increased 17% from 2,791 BOE per day to 3,258 BOE a day, primarily because of the Diamond M properties.

Additionally, production from the New Mexico Wolfcamp increased 6% from 2004 BOE a day to 2,117 BOE a day. In the third quarter, as you can see, we had a 1% decrease in the Barnett Shale gas project from 2,495 BOE a day to 2,472 due to the natural decline and timing of completions and connection new wells to pipeline. We anticipate volumes to increase in future quarters, basically depending on the timing and completion hookup of wells. As of September 30 we had approximately 33 gross wells in progress.

I want to caution you. Due to uncertainties associated with initial decline rates of new wells and uncertainties associated with timing of takeaway capacity and related pipeline expansion and compression, management cautions investors not to place undue reliance on estimated net daily production for the purpose of estimating the company's future net daily volumes.

Moving to Slide 14, we have revised our 2008 budget. It's currently, the budget is $153.9 million, which is a 10% decrease from our previous budget of $171.6 million. Fourth quarter of '08 CapEx budget decreased $17.7 million or 43% from $41.3 million to approximately $23.6 million. [break in audio]

The $17.7 million decrease relates to fourth quarter activity only and is allocated as follows: $14.2 million is associated with 9 gross, 9 net well decrease in the company's previously planned drilling activity in New Mexico; $2.3 million is associated with the deferral of 3 gross, 2.6 net wells in the Diamond M Canyon Reef project due to unavailability of a drilling rig until early November of '08; $1.2 million is associated with the deferral of 3 gross, 2.9 wells in the Utah/Colorado project due to delays in permitting. As of September 30 the company had invested approximately $130.3 million of the revised $153.9 million budget.

Moving to Slide 15, our preliminary 2009 budget calls for $118.8 million, which is a 23% decrease from the revised '08 budget of $153.9 million. Based on this preliminary budget, we have budgeted as follows: $61.7 million for the Barnett Shale; $14.9 million for New Mexico; and $40.4 million for the Permian Basin. Of the $118 million budget, approximately $106 million is for drilling and completion of 100 gross, 62 net wells, and 45 gross, 40 net workovers and conversions. And approximately $12.9 million has been budgeted for purchase of leasehold and seismic.

We do intend to fund our estimated $118 million '09 CapEx budget out of operating cash flow subject to each project's individual rates of return, our continual review of commodity markets, service costs, economic conditions and other factors.

At this time it's my please to introduce Don Tiffin to you and he will review the company's operations, reserves and major properties with you. Don?

Donald Tiffin

Thank you, Larry. My format's going to be a little bit different today in that rather than just moving straight into the operations review I'm going to spend a few minutes talking a little bit about our strategy and trying to help you understand a little bit about where the decisions we're making come from and the basis behind all those and hopefully, like I said, you'll have a better understanding of where we're heading.

Moving to Slide 17, many of you have heard us talk about the attributes that we look for in any project that we're considering to add to the portfolio, and basically these four are attributes - quality, control, impact and running room.

When we talk about quality, specifically we're talking about strong performance metrics - rate of return, payout, net to investment ratios, lifting costs, finding and development costs, things of that nature. We're also talking about maturity or asset maturity in regard to an old producing property or a young lease play, basically looking for assets that are young in the maturity curve.

In terms of control we're looking for majority ownership or operatorship and, in most cases, both. And this really gives us the ability to dictate expenditure timing and control the technical aspects of the development.

In regard to impact we're talking about making sure that anything that was add to the portfolio is meaningful with companies. We're a relatively small company. We have 43 employees. We have the lowest headcount in our published 19-company peer group. So, again, it's very important that the things that we do really matter. And as an example of that, if we look at mid-year public data, we rank number one in terms of net operating cash flow per employee, number one in terms of developed reserves per employee, and number two in terms of proven reserves per employee. So it's something that we're very conscious of and we make sure that we're not wasting our time on less-impactful projects.

And then the fourth component is running room, and obviously we're talking about future development being drilling locations, secondary tertiary recovery or some combination of all of those.

These four attributes, we believe, are critical regardless of the environment that we're working in. Obviously, there were important during a high commodity price environment. We believe that now they're more important than ever. And as I move through the specific projects, you should be able to see how each one of them conforms to the criteria.

Now moving to Slide 18, since 2002 our primary focus has been to build the portfolio and to focus on reserves and production growth. Obviously with changes in both equity and commodity markets, we're now looking at a little bit different strategy, at least in the near term. So for the remainder of 2008 and for 2009 we'll be focusing on funding CapEx through cash flow, as Larry has already pointed out, and allocating discretionary CapEx based on rate of return to make sure that we're maximizing cash flow off of each of those invested dollars.

The Barnett Shale is our only non-discretionary major project. It's operated by Chesapeake, as you well know. And as such, we'll fully participate in all Chesapeake drilling activity in the AMIs or areas of mutual interest where we have ownership.

Parallel does control all other major projects - in New Mexico, Wolfcamp; Diamond M, Fullerton, Harris and Carm-Ann. None of these projects have extenuating non-fiscal drivers such as expiring leases, contractual development stipulations or technical imperatives. And then finally, as I've already pointed out, the capital allocation will be very much rate of return driven.

Now moving to Slide 19, Larry presented this slide to you just a few moments ago. Let me draw your attention specifically to that lease operating expense of $10.14, then if we can move to the next slide, Slide 20, I'll go over the breakdown of that $10.14.

The pie chart provides a good graphical representation of all the major cost drivers year-to-date for 2008 - well repair, facility expenses, well treating, water hauling, electricity, labor, and other miscellaneous direct charges account for almost 60% of the total. Non-direct items such as ad valorem taxes, marketing, transportation costs, and allocated overhead amount to just over 30%.

One thing I would really like to point out is that well repair, electricity and well treating, which account for about 32% of our LOE are directly linked to both commodity prices and activity levels. As commodity prices have dropped over the course of the year and as activity levels industrywide come down and bring down the cost of goods and services, we do expect overall lifting costs to drop even below the $10.14.

As a side note, at mid-year 2008 Parallel took a look at the 19 companies in the peer group in regard to a number of metrics, but specifically on LOE in this case, and ranked at just below the median in 11th position out of the 19 companies.

Now when we step back and dissect that a bit further, we find that there are 10 companies in that peer group that are predominantly gas producers. There are 9 companies that are predominantly oil producers, of which Parallel is one of them. Comparing ourselves with the oil-dominated companies, there is only one company with lower lifting costs than us. So again, we're very conscious of our lifting costs right now. Our lifting costs are very attractive. We do expect them to come down.

One of the things that we do from an operational standpoint is make sure that we're looking at every area and trying for cost reduction. Well repairs are an area that we pay particular attention to, electricity, things of that nature. But bottom line is on both the capital that we invest and the operating expenses that we pay, we're trying to make sure that we're maximizing every dollar.

Now let's move to Slide 21 and we'll talk about capital a little bit. The curve or family of curves that you're seeing on this slide are single well rate of return or single well economics for the major projects that we're involved in. And as you can see, we run pricing from $50 oil and $5 gas on the left-hand side over to $100 oil and $10 gas on the right-hand side.

Each one of the curves are statistical type curves in that we take a look at our experiences to date on a particular project, prepare basically an average type well, we apply third quarter service costs to that at these various pricing scenarios, and calculate rate of return at each position. Generally speaking, a 25% rate of return is our economic threshold for any project, so you can see just by looking at the bottom of the page where each project would begin to be unattractive for us.

You can see the first project to fall out would be New Mexico, which at about 750 gas, based on our type curve, is something that we would begin to back off of. On the other end of the spectrum you see that even at $50 oil the Diamond M Canyon Reef is still generating a 100% rate of return.

Now let me talk just real briefly about type curves for each one of these projects, beginning at the top. Diamond M, our type curve is 75 barrel initial rate to 100,000 barrel EUR and $850,000 drilling complete cost.

Now, one thing I do want to point out on all three oil properties or all three oil projects, we're looking at primary recovery only, not including any reserves or production or secondary or tertiary components, as the case may be.

Moving on down the curve, at Harris were looking at a 60 barrel a day initial rate, 85,000 barrel EUR, $700,000 drilling complete costs.

Carm-Ann, 45 barrel a day initial rate, 80,000 barrel EUR on primary, again, and a $700,000 drilling complete cost.

Barnett Shale we're looking at a 3.1 million a day initial rate, a 3 Bcf EUR, and a $2.8 million investment.

Now, Chesapeake had released some data just a couple of weeks ago in their analyst presentation that gives a little bit different numbers in that they're showing a 2.5 million a day initial rate and a 2.65 Bcf EUR. If you look at the data that they've presented, they are averaging those results across all of their Tier 1 area, which includes about six counties. And if you have access to their particular presentation, if you hone in a little bit closer to that specific Tarrant County area that we're a partner in, just east of Fort Worth, you'll see that they've got significantly better results, and that would explain the difference between the numbers that we're using and the numbers that they're using.

And then finally on New Mexico, our type curve if 1.4 million a day initial rate to a 2 Bcf curve and a $2.3 million drilling complete cost. Now I would say that in New Mexico we've been seeing some really nice results in some of the latter wells. The most recent well that we brought on is the Gate Dancer 2. It's been on production about three weeks, had originally come in about 4.4 million and as of this morning was making 3.6 million. So we do have significantly better wells than some of these but, again, we're talking about average wells and type curve drilling.

Now let's move to Slide 22. The bar chart here is capital allocation. Again, this is preliminary 2009 CapEx. It just elaborates a bit on some of the numbers that Larry has already given you. This is by project and category and, if we begin over on the left-hand column, we can see that the Barnett, as we've already pointed out, is our largest project for the year - $61.7 million or about 52% of our total. The Permian oil, if we group that, would be Diamond M, Harris, Fullerton and Carm-Ann, represents about 32% of our CapEx for the year.

Now if we break that down in terms of activity, just looking across, we're going to spend about 80% of our total budget on reserve and production development, basically drilling and workovers. That would be 82% for drilling, 4% for workovers, and then about 11% for leasehold costs. So as you can see, the bulk of our investment's going straight into the ground for next year.

Moving to Slide 23 we can get a little bit of a feel for CapEx timing. As we've already pointed out, the development of the Barnett Shale based on Chesapeake's drilling schedule that they've provided is that they basically will be running four drilling rigs throughout the year, fairly uniformly, fairly consistently, so we've just modeled in this four rigs throughout the year for a total of 48 wells, and you see that red component.

Now on the discretionary CapEx that you see, you see that it's very much backend loaded. We do have a bit of drilling coming in during the first quarter. We begin to ramp that up in the second quarter and then the fourth quarter is actually our highest investment period for the year.

There are a couple of reasons that we're doing that. First off, we would like to see where commodity pricing is going to be headed for the year. We do believe that we're in the dip at this point. We hope that we are at the bottom of the dip and hope that we'll see strengthening throughout the year. So that's the first reason.

The second reason is if we look at cost of goods and services, we've not yet begun to see cost of goods and services coming down in response to the reduced commodity prices. There's always a lag, either the commodity prices increasing or declining. So just as when commodity prices began to elevate there was a time period for goods and services to catch up; the same situation is true on the downhill slope, too.

Now let's talk a little bit about what's going on. Slide 24 is our work in progress slide, and, as you can see, we have a number of wells in process at the end of September, 38 gross or 12.7 total. And looking through the chart you see that most of that was in the Barnett. This is not an unusual pattern. It's associated with development on past sites and the building of gathering system and making sure that we get lines to those wells as we move along. But at the end of September we had 8.7 net wells shut in.

Now one thing that we cannot do is underestimate the impact of those wells awaiting production and preproduction status. As I just pointed out two slides back, we're looking at a type curve of about 3,100 initial rate and 8.7 wells. If you net that out you can see that, just in terms of initial first-rate production, we're looking at something well over 4,000 BOE a day. Now it's not going to all hit at the same time; it's not going to hit all at once. But it does give you an indication of the order of magnitude that we're talking about in terms of work in progress.

Looking on down the list, in New Mexico, three wells, that's fairly typical. We really don't have much timing delay in New Mexico. And then the same thing in the Permian Basin, very little timing delay in the Permian oil.

Now let's move right to Slide 26 and we'll talk a bit about the Pacific projects. And again, I'm going to move through these fairly quickly so we can spend some time on questions and answers.

At the end of the quarter, the acreage count in the Barnett stood at 32,900 gross acres, a little over 9,800 net leased acres, of which about 11,600 gross and 4,200 net were in the halo area outside the floodplain. Production was essentially flat quarter-over-quarter and we'll see the plot in the next slide, but essentially flat quarter-over-quarter, very slight dip.

Our 2008 CapEx is basically unchanged from the first of the year. We do expect to spend $74 million in the Barnett and by the end of the year we'll have drilled 53 wells and continued with the leasing campaign in the Barnett. 2009 we've already talked about a bit - $61.7 million in CapEx, which would allow us to drill 48 wells, all Chesapeake operated, and continue to modify the leasing campaign.

Now let's move to Page 27. This is a net production history in the Barnett, and specifically, if you'll start over on the left-hand side and look across the curve you'll see that the production build, the yellow area, has been very much stair step in nature.

And we've talked about this, I think, at every conference call for the last several quarters, and again, this is basically a function of the pad development. Typically Chesapeake will go in and drill fills on a pad before moving a completion rig in. That's just purely space limitation. And then you'll have four wells completed at once and basically coming on at the same time, assuming there's a gathering system there in place.

If we look across the last two quarters we see that our net wells have basically been flat at 20. And again, there's that moderate decline that I was talking about.

Now let's go back to the work in progress that we mentioned just a few moments ago. With 31 wells in post-drilling status, you're looking at 8.2 net wells or, if we look at the drilling wells also, we're looking at 8.7 net wells. That's 44% of the 20 wells that we're showing here. So once again, we have just a huge pent-up potential that will be coming on production at some point. Our problem is we just can't tell you exactly when.

Now let's talk about New Mexico a bit. This is our gas play. This is in New Mexico, the [horizontal] Wolfcamp. Moving to Slide 29, if we look at the leasehold trend map or the trend map in the insert on the left-hand column - again, we typically about New Mexico in three areas, the northern area, the central area, and the southern area - in the northern area we presently have 55,000 gross, 53,000 net acres leased; 10,000 gross, 6,000 net in the central area; and 41,000 and 26,000 net in the southern area, for a total gross acreage count of 106,000 acres and a total net acreage count of 85,000 acres.

During late 2007 the company dropped to one rig in New Mexico and began to focus on 320acre drilling and 160-acre development on the north end, specifically in what we call the County Line area or this purple area. This is an area where we've had very good well performance and much more consistent performance for just better overall performance in this area where we wanted to focus on.

We also made the decision at that same time to pull out or back off or slow down the southern area while we were shooting a very extensive 3D seismic survey. That survey is now complete. We've received what we believe is the final data set this past week, and we have begun interpreting that in earnest. We'll continue that through the rest of this year and well into next year. And again, the whole purpose of the 3D was to identify areas with natural fracturing, which are typically associated with some very, very big wells, in one instance a well that was capable of producing as much as 12 million a day down on the southern end.

As you can see on the production, we were up about 6% quarter-over-quarter. This is a continuation of, again, that more consistent well performance on the northern area in the County Line area.

We have revised our budget in New Mexico to $50 million for the year. That would allow us to drill 18 wells, finish up the 3D, which we have done, and continue to basically provide maintenance on the leasehold. Virtually all the acreage that we consider productive in the area has been leased up and basically we're renewing leases and picking up just fringe acreage in some instances.

For 2009, we expect to spend about $14.9 million. That will allow us to drill six wells and, again, continue with the leasehold. And, as I've already pointed out, that is backend loaded. That would be fourth quarter. And one more time, we're doing that to allow gas prices to stabilize at hopefully a higher level and also for the drilling costs and completion costs to drop back in line with commodity pricing. And specifically on the southern end, it gives us time to interpret the 3D.

Now moving to Slide 30, as you can see on the production plot, the strategies worked quite well for us. Our most recent completion, which I mentioned a few minutes ago, the Gate Dancer 2, came in at about 4.5 million. There's currently about 3.6 million after almost three weeks. And it's been a very - but as you can see in the curve, we've had very steady growth since dropping back to one rig and essentially steeper growth than we had prior to that. So we've really gained capital efficiency in New Mexico by shifting our focus, and we expect it to only get better.

Now one thing I can point out about the Gate Dancer 2, this most recent well, is that it is our first 160-acre well. Right now we have two wells that are awaiting completion. They'll be fraked next week. They're in the Gate Dancer area, and both of those wells are 160-acre wells. We have one well that's drilling right now, also a 160-acre location, and then our intent is to let that rig go at that point and complete these next three wells and begin to formulate a game plan for next year that would be fully dependent on commodity pricing.

So we've got a lot of flexibility in New Mexico and, as I pointed out earlier, no burning fuses, if you will, on the leasehold.

Now let's talk about the Permian oil assets a bit. Moving to Slide 32, the core Permian oil assets include Diamond M, Harris, Carm-Ann, and Fullerton. And as you can see on this slide, they go back to the idea of control. With 85% working interest and 71% plus or minus net revenue interests, the company controls every one of these major projects. In aggregate they're about 18,500 acres. All of the properties basically immature water floods or water floods yet to be installed, and we'll mention that a bit more as we move along.

In terms of net daily production, we had good growth quarter-over-quarter. We were up about 13%. That was primarily due to development in all of the major areas in the acquisition of Southwestern's interest in the Diamond M.

Looking on down, in total we'll spend about $26.1 million through the course of the year. We drilled 31 wells, and completed about 67 workovers. Most of the work has been done. We do have a bit of remaining work to be done in some of the projects in terms of workovers, and we're finishing up our last three weeks at Diamond M as we speak.

In terms of 2009, we do expect to spend a little over $40 million. That would allow us to drill 44 wells, do 45 workovers. In all likelihood, the number of workovers will increase.

Now moving to Slide 33, this is a composite production plot or a stacked production plot for the major Permian assets. You can see that we had a nice little uptick, that 13% uptick during the last quarter. And if you follow that back down you can see that that was primarily the result of development in all areas, but especially Diamond M, where we drilled six wells that came in in total with about 500 barrels gross. And we were also able to pick up the additional interest owned by Southwestern that began to show up in the quarter.

Now moving to Slide 34 we'll talk a little bit more specifically about Diamond M. Our current operating working interest is 88%. That's after the acquisition of Southwestern. And I can say we're very excited about the potential. We've said for a good while now that this is our [inaudible] potential asset, with about a 30 million barrel oil target.

Virtually everything that we've done out here in terms of oil development over the past several years has worked quite well. Our current type curve, as I pointed out a few slides back, is 75 barrels a day initial rate, 100,000 EUR. And once again, this is primary reserves only. This is very much a water flood project and ultimately a CO2 project, and those reserves and that production has not been accounted for here.

During 2008 we'd originally budgeted to drill 12 wells. We were going to do that in two sixwell packages, one early in the year and one during the fourth quarter. The first six-well package worked out very well for us. The six wells, in terms of combined daily initial rates, were a little over 500 barrels. We had two wells come in in the 140 barrel a day range. So very good wells, better than type curve in aggregate, and very, very encouraging.

We have spudded the last three wells - what will be three wells this year; we've dropped that budget back from 12 wells to 9 wells due to rig availability - and the first of the last three wells was spudded the day before yesterday, and we should have no problem getting these three wells drilled before year end. We'll continue to keep that rig past the new year and drill the remaining three wells of what, again, would have been the six-well package for the fourth quarter of '08.

And then beginning in the second quarter some time we expect to move a rig back into Diamond M and drill an additional 18 wells.

In addition to the drilling next year, where we expect to drill 21 in total - basically the three from this year and 18 for next year - we'll also be doing some workovers, some [deepenings] and conversion injection - for a total of about $19.5 million.

Now we can look real quickly at the historical performance of Diamond M on Page 35 or Slide 35. I think the most important thing to point out on this slide, if you look back at the drilling and it's not all completely annotated here, but since 2002 there have been a total of 12 wells drilled at Diamond M and about 25 re-entries.

You see - over on the right-hand column you see the production build coming off of the most recent six wells, taking production to north of 1,000 BOE a day in August. You see a very nice response to those six wells. This is a gross plot, so the acquisition doesn't factor in here. But my point is you're looking at a 500 BOE a day build out of five wells. Between the fourth quarter of 2008 and 2009, we will drill a total of 24 wells, so that doubles the number of wells that have been drilled to date. And [inaudible] visual impact, you see the impact of the first [inaudible] drilled this year. So, as you can see, we're very excited about the opportunities at Diamond M.

Now, moving over into the Andrews-Gaines County Line, we'll talk a bit about Carm-Ann. Again, with 77% ownership, we control the property. We acquired the property in 2004 for the purpose of down spacing from 40 to 20 and ultimately 10 acre spaces to implement water flood and to continue to stimulate the existing wells.

Unitization is well under way. We've completed the engineering work, we've completed the land work, and we are now distributing ratification letters to royalty and working interest owners. Once that ratification is all back and we've received sufficient approval there, then we'll present the data to the Railroad Commission of Texas and go before a hearing and hopefully have the thing unitized some time in the second half of [break in audio].

Looking at recent activity, we had budgeted for 2008 the drilling of five wells, the workover or conversion to injection of six wells. I can tell you that all five wells have been completed. They came online between late June and late August at combined initial test rates of about 240 barrels of oil a day.

2009's going to be relatively quiet. We're going to be spending most of the year basically working through the unitization process and then, hopefully in the second half of the year, we'll be looking at a budget revision to ramp activity up. But right now we're looking at basically $400,000 to either convert or workover five wells prior to water flood.

Production plot on Slide 37 shows the development of Carm-Ann at this point. You see a moderate incline there beginning right before June or in June of the five wells. One thing I can say is the impact of these new wells, as I said, about 240 barrels a day gross initial production, has been moderated or mitigated by gas line pressure.

It's interesting to note that particularly in this Harris, Gaines County, Andrews County area that the gathering systems are so reliant on gas takeaway capacity on the Gulf Coast, primarily on liquids extraction, so we've had excessive pressure. All of that translates back to the wellhead and down to the formation and holds back pressure on the formation. So we've somewhat suppressed our oil production just by gas system backup pressure, which now is beginning to work itself out.

Harris was acquired a year after Carm-Ann basically. It's about a mile west of Carm-Ann and we bought it for all the same attributes - 40 to 20 acre [inaudible] then ultimately down to 10. We are also interested in putting in water flood, just like Carm-Ann, and then doing additional well stimulations.

The water flood implementation is happening now. We are in the very final days of receiving Railroad Commission approval. We're moving forward with plant construction, pilot water flood plant and [inaudible]. And we have three rigs working on conversions to injections right now. Our goal is to have water in the ground beginning on about January 15, and right at the moment it looks like we probably will make that.

For 2008, at Harris we had expected to spend about $7 million to drill 10 wells and do about 16 workovers and conversions. The 10 wells were all drilled and went online between early June and late September at a combined test rate of about 654 barrels of oil a day. And, as you can see, that's right in line with the type curves that we talked about a few minutes ago. Today we have three workover rigs working on conversions, getting ready for that injection beginning in January, like I said.

For 2009, we expected to spend about $15.8 million. We planned to drill 20 wells assuming that commodity prices and goods and services behave themselves, and we'll also do another 20, 23 workover conversions, mainly in the development area.

Moving over to the production plot, we see a nice little response there at the end from the dip in June in response to the 10 wells that we had drilled. October production is right at 800 barrels a day, so you can see that we've got a nice little response and we're waiting, again, for water flood to begin in January. And you see that same footnote in regard to the gas pressure, gas system back pressure suppressing production on the well.

Now, moving to Fullerton, Fullerton, as you all well know, is a property that we acquired in [inaudible]. We did it for a lot of reasons, but, again, it has all those attributes that we're after. We have control, we have quality, we had running room, we had opportunity. Just kind of as a little bit of a history lesson, we bought the property in December of 2002. At the time we acquired 9.2 million barrels for $42.6 million. Since then we've produced about 3 million barrels of oil, and at mid-year '08 we had 9.3 million barrels remaining, so nice performance from a reserve standpoint.

But just as importantly, during that timeframe we have produced in excess of $50 million of excess free cash flow, which was the primary purpose of Fullerton, and that was to find a property that would fund not only itself but also help to fund other projects, and this property has done a very good job of doing that.

During 2008 we had budgeted $4 million to drill seven wells. We've actually drilled five and we'll stop at that for this year. We've completed the first four, and those four wells are on this combined initial test rate of about 198 barrels a day. We also have a couple of workovers that we've done throughout the year. In 2009 we expect to drill three wells, and we'll also be doing a number of workovers and we'll make that provision later.

The production plot on Slide 41 is a little bit misleading in that the [inaudible] actually starts at 1,500. So you'll see production fluctuates across a relatively tight band from around 2,300 to about 2,000, so just a tight band. If we look over, again, on the right-hand side, we'll see that same note. Again, Fullerton, Harris and Carm-Ann are all in the same area. The gas goes into the same system, so they all have suffered from that back pressure associated with the hurricane on the Gulf Coast. I can tell you that October production was a little over 2,000 barrels a day, so we're back up there where we should be with the property.

Now, just moving to the last slide, which is a summary slide, what can we say? We can say that third quarter we had production at record levels, in excess of 8,200 BOE a day. We also had record levels of work in progress. The first thing that you might suspect is that, with a budget of lower than [inaudible] spending in 2008, that production build might suffer. But let me just throw some numbers out very quickly.

If we look at the Barnett Shale and we assume type curve performance there and, again, initial production rate all coming on at the same time - which is not going to be the case, but just as an example - about 4,500 barrels a day out of the Barnett, if we play that same game with Diamond M, assuming all production comes on at once, about 1,300 barrels a day, and if we look at the development on the Harris, again, about 600 barrels a day. Now obviously the initial test rates are going to be spread across the year, but this is [inaudible] performance. So in spite of $118 million budget for next year, we should have very good production build throughout the year.

One additional comment on the Barnett, the number I just gave assumes that none of the new production on the 48 new wells that are drilled throughout the year come offline and this is just taking care of the wells that's work in progress at this point.

Now in terms of profitability, as we pointed out, very low cost structure - $10.14 of DOE. Now realize pricing from operations through the end of September was $72.73 per BOE. If we back out the $36 million that was written for hedges and get back to a net effective realized price after hedges, we actually received year-to-date about $56. Going back and looking at some of the hedge numbers that we were talking about, in 2009 we're looking at, on that 2,400 barrel hedged volumes, we're looking at a floor of about $70. So 2009 from a pricing standpoint looks to be very good relative to 2008, in spite of the fact that the market has pulled back strongly.

The other two points under profitability, we saw in a previous slide that all the oil projects were attractive at NYMEX pricing in excess of $57 a barrel, and we saw that Diamond M generated a 100% rate of return even at $50 NYMEX.

And then finally, in terms of flexibility, only the Barnett Shale is nondiscretionary. All other projects are Parallel controlled. Capital allocation will be focused on rate of return and cash flow, and capital expended can be expanded or contracted depending on what's going on with commodity prices and cost of goods and services.

So, again, it all goes back to the portfolio. We've got a good portfolio. We've got a very diverse mix. We've got good balance between oil and gas. We have a lot of cards that we can play. And in spite of the low pricing, 2009 looks like a very good year for the company.

And at that point, I'm going to stop and we can go to questions and answers.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from [Unidentified Analyst] - Jefferies.

Unidentified Analyst - Jefferies

First, on the $118 million of CapEx within cash flows, what sort of an estimated commodity price?

Larry Oldham

$70 oil and $7 gas.

Unidentified Analyst - Jefferies

Okay, $70 and $7 net realized.

Larry Oldham

No, sir. NYMEX.

Unidentified Analyst - Jefferies

And what's the cash position after you took the bank debt down? Should I just add your sort of cash in the quarter to what you took down?

Larry Oldham

We'll be around $60 million today.

Unidentified Analyst - Jefferies

And is this sort of dry powder or how shall we think about sort of the use of that money? Or is there a market unfolding here where you could make sort of a countercyclical purchase of some type?

Larry Oldham

Basically, it's dry powder. And yes, we are positioning. We're always looking for a quality acquisition. And, of course, during a very depressed, I'd say, down market now with oil prices dropping from $140 to the $60 plus dollar range. I believe it's up today to $70, but we're in a very, very volatile environment. But the primary purpose, [Sabash], was to have dry powder and have a high degree of liquidity so we can maintain financial flexibility at all times.

Unidentified Analyst - Jefferies

And in the Barnett position, I guess, you know, Chesapeake's committed, it looks like. Some other parts of the Barnett they're not, but here they're committed with a four-rig program. Longer term, is this sort of an asset base you could flip for something else or do you see this core to your operations over the long term?

Larry Oldham

Well, today it's core because it's in the early development stage, Sabash. As you can appreciate, we have about 10,000 net acres, and on 40-acre spacing, you're looking at - let's see, well, we have 32,000 gross acres - on 40-acre spacing, we're looking at probably 750 gross wells. And to date we've only drilled about 110 wells, so it is a multi-year project.

And the big part of this project is getting the leasehold costs, which we now have; getting the infrastructure built, which Chesapeake is in process of building; and once that infrastructure's in place, it's going to be perpetual motion and basically a cookie cutter and a gas manufacturing project.

So it is a core piece of what we're doing today but, in answer to your other question, there's always the possibility that we might sell the project in the future and then reinvest that capital in either a quality acquisition, the Permian Basin, or pay down debt. We have a lot of options available to us.

Unidentified Analyst - Jefferies

On the infrastructure, some more clarity on when do you think it's to cookie cutter stage?

And then the final one is, of the roughly nine net wells waiting on completion in the Barnett, do any of them share a common pad to where they might be completed at the same time?

Donald Tiffin

The infrastructure, again, is basically coming together. The second portion of the question regarding the wells sharing pads, a number of the wells - keep in mind that's 8.7 net wells and 33 gross wells - but of the 33 gross wells, a number of them share the same pads. We're talking about multiple pads.

Larry Oldham

Sabash, these wells are all the way from eastern Tarrant County on the Dallas County line down the Trinity floodplain all the way through downtown Fort Worth to the west of downtown Fort Worth approximately four miles. So you have like a 20-mile area here at least where these 33 wells are scattered.

And we're drilling four wells a month right now, primarily due to lease obligations. We don't expect the rig count to increase and we do not expect it to decrease.

Operator

Your next question comes from David Heikkinen - Tudor Pickering & Co.

David Heikkinen - Tudor Pickering & Co.

Just following on that question about the net wells and thinking about them not being in production, can you talk a little bit about the borrowing capacity as you get those on and kind of what you would expect your borrowing base to do as you roll through the rest of 2008 and 2009?

Larry Oldham

Well, those 33 wells are not in our borrowing base today, so we do expect the borrowing base will improve as the wells come on.

Now, we have a $230 million borrowing base today. Based on the bank's price decks, that borrowing base could be increased quite a bit. But we have chosen not to do that currently because we didn't want to increase - we'd have increased fees associated with that borrowing base increase and the fact that we feel like we've got sufficient dry powder now and we're going to live within our cash flow, assuming we maintain a reasonable price deck as we move into '09.

If we see we need more capital, then we can go back to our banking group and request an increase in the borrowing base.

David Heikkinen - Tudor Pickering & Co.

And kind of thinking along the same lines, like the disclosure of using 6 and 60, the impact on reserves and the 17% downward move from midyear, how does that impact your bank lines as well?

Larry Oldham

Well, at 6 and 60 we still have a borrowing base that's greater than our current borrowing base at [inaudible].

David Heikkinen - Tudor Pickering & Co.

That's good to know. So really, from a liquidity standpoint, cash flow, cash on hand should be no issue. So kind of thinking about stock at $4, you spent a lot of time on the operations side. Your financially in a good position. What are people missing? I mean, what do you think people are thinking now?

Larry Oldham

You know, David, the last 60 days we've been in an environment that I have never seen in my whole career. Most folks on the phone haven't seen it. You've had oil drop from $140 to $60. Gas prices go from $13 to $6. You had this huge financial crisis, which is a global issue. We're all dealing with this high volatility and uncertain product price environment.

And from our perspective, we're looking for stability. And this is the third meltdown that I've been through personally; I was involved in the one in '86, the one in '98, and this one, we were well prepared for it. And so what we're looking for is stability, and we are monitoring our budget and our cash flow every month and we're not going to get ahead of ourselves.

And basically, you know, I'm very confident that we have our eye on the ball. We've run all the tests. I mean, we run all kinds of numbers, what if cases, and I think we're very prepared for whatever comes our way.

So, you know, I don't feel like that we management or that we do not have our eye on the ball. We really do. And one reason we pulled back, David, on CapEx is that, if oil prices do deteriorate and stay down low, service costs are going to come down pretty hard. And if you're out burning capital today, you're overpaying for those services, which that's wasting money. And at the same time, what if you get an additional downward price environment? So it's a double cut. So right now is the time to be very patient and stay very, very liquid, and that's what we're doing.

David Heikkinen - Tudor Pickering & Co.

Thinking about just one operational question now on the Barnett, how is it possible to continue to build that backlog of wells? I mean, are there any implications that we should read into kind of how Chesapeake is investing capital? Or is it just normal operations that said wells didn't get put on production?

Donald Tiffin

I think the best way to answer that, David, I think it's just normal operations. I mean, the thing that is truly unique about what Chesapeake's doing there in that area are these pad sites. There are a total of 75 pads. Right now we're working on somewhere between 25 and 30 different pads.

Once you get the infrastructure, the gathering system to the pads and then you're basically up and running. But right now they're still working through that process. So for the foreseeable future, you know, somewhere in the 30 barrel backlog is probably going to be the case. Once we get more and more pads on and get more and more flow lines, infrastructure, gathering systems in place, then hopefully that backlog would begin to diminish.

One thing, too - and it kind of goes back to the borrowing base question that you had - if I go to, you know, Slide 14 in Larry's portion of the presentation on the Barnett, at midyear we had 4.3 million BOE booked, and that would be attributable to the remaining reserves, almost 20 or so net wells that we had. If these 8.7 wells that are works in progress in the Barnett are type curve wells at 3 Bcf, you're looking at about 4.4 million BOE net. So, again, it's very difficult to underestimate the importance - or to overestimate the importance of those work in progress wells.

David Heikkinen - Tudor Pickering & Co.

Trying to hone in on the same question Sabash asked, kind of the infrastructure and timing, you said foreseeable future. Is that first half of next year, is it all through 2009? I'm just trying to put a definition on foreseeable future with 30 wells in backlog.

Larry Oldham

We're expecting to see a nice increase in volumes here in the first half of '09. If you roll forward  let's say that we were at 33 wells at September 30. We're going to add another 10 to 12 wells by January 1. So you're going to be at roughly 40 plus wells January 1. We're expecting to see a nice surge in volumes during the first and second quarter, and that doesn't count the additional 48 drills that are going to be drilled during '09.

David Heikkinen - Tudor Pickering & Co.

What's the continued pull forward of 10 or 12 wells per quarter that just continue to build into backlog in the first quarter?

Larry Oldham

There should be a netting effect. As we drill a dozen wells a quarter, then hopefully we'll be bringing on a dozen wells a quarter.

At some point in time when the majority of that infrastructure and gathering system's in place, this will no longer be an issue. And so the timing of when the wells are drilled and in completion should be more into the maintaining process.

David Heikkinen - Tudor Pickering & Co.

On that, on the Board level, have you had a strategic discussion of how you could get control of operations in the Barnett or is it just too much people and Chesapeake has too much mass that you'd even want to consider it?

Larry Oldham

It would be an army of people. This is a very, very complicated operation. Don?

Donald Tiffin

Yes. First off, we don't have a majority interest. I mean, we're at 35%. They have the remainder. So, you know, just by virtue of ownership, that would be a huge, huge mountain to climb.

The other thing, too, just from a practical standpoint, there are a lot of moving parts there. The land services are still predominantly handled by [Dale] Land Services on a contract basis, so you've got that portion of it. Then, of course, you know, being right there inside the city of Fort Worth and surrounding areas, you've got a lot of regulatory, a lot of hassle to deal with.

The fact of the matter is, you know, I made the point we try to be very efficient with our time, and I think our metrics prove that out with the 43 people that we have. If we were operating the Barnett, our numbers would go through the roof and our efficiency would drop incredibly.

Operator

Your next question comes from Pavel Molchanov - Raymond James.

Pavel Molchanov - Raymond James

A quick question about your non-core area - since nobody asked you about this, I thought I might  the East Texas assets and your Rockies assets. I mean, clearly it's kind of a meaningless part of your CapEx. Do you just envision maybe selling that one of these days or do you still want to keep those assets?

Larry Oldham

Well, there's two parts to that. The East Texas asset, we're getting to spud a gas well on about a 10,000 acre block that we own a quarter interest in, and that'll take about 45 days. If that well is successful, it could set up a meaningful development.

With respect to the Utah/Colorado, we're looking to joint venture that asset with a triple play that has Rockies expertise. So we are in the process of trying to find a partner for that.

Pavel Molchanov - Raymond James

When did you say your first East Texas well is going to be completed - or you're just spudding it, I guess?

Larry Oldham

It should be spudded on or before, say, December 1.

Pavel Molchanov - Raymond James

And any sense of the timing on that?

Larry Oldham

It takes probably 45 days to drill the well and have it cased. It'll be a first quarter either dry hole or completion attempt.

Operator

Your next question comes from Leo Mariani - RBC Capital Markets.

Leo Mariani - RBC Capital Markets

A question about your drilling program at Harris. It sounds like you guys are going to drill a number of wells next year. I'm just curious as to kind of what your approach is going to be there. Obviously, I know you guys are trying to water flood the field as well. Do you plan on drilling all these wells and [turn them for] production for a period of time and watch the rates and eventually convert them to injection? Or just try to give us some sense of when and how we should be expecting some climb in oil production from all these wells you're going to be drilling next year.

Donald Tiffin

Right now we have 20 wells budgeted for Harris. Obviously, that could drop if oil prices weaken or if goods and services don't come down. But, assuming that those 20 wells do get drilled, they'll be drilled primarily in the water flood developmental area. That's where all the workovers that we're doing right now are occurring. I mentioned we had three workover rigs in the field right now. Those are preparing wells to move to conversion to water injection.

Now just as a course of practice, typically when we convert a well to injection or get ready to convert a well to injection or drill an injection well, we'll put the well on production for a period of time, mainly to condition the well before we begin to inject water in it.

So in terms of production build, which I think is probably your real question, the drilling at Harris is going to be second half drilling for the 20 wells that we're talking about. We should be moving into - we should have fresh water going in the ground about mid-January. We would expect first response anywhere from three to six months and peak response about a year out.

I'd like to be able to tell you with good confidence what we expect that peak response to be. We're very optimistic, but we're also pretty cautious, so I'm not going to tell you what we expect it to be.

Leo Mariani - RBC Capital Markets

Jumping over to New Mexico, you guys obviously have a lot of leasehold over there. You've got a little over 100,000 acres. Can you give us a sense of what the terms are on some of that lease  obviously you're taking your rigs off the property over there - in terms of how much of that acreage is held by production and outline your drilling commitment for the foreseeable future?

Larry Oldham

Well, on the southern end, where our seismic is being interpreted, I would say 90% of that is federal long-term leases. On the northern end we have some federal and we have fee. With respect to our fee leases, we have leases with kickers - with two-year kickers - and a lot of our - we've been drilling wells on 320, so we have HBP'd a number of inside 160-acre locations.

On the other acreage, again, we have a lot of term remaining on that acreage so we're not under any hurry or we're not worried about expiring leases where we have to run out and drill just to hold acreage. So we're in good shape as far as lease expirations are concerned.

Leo Mariani - RBC Capital Markets

So when you say a lot of term, can you quantify that for us?

Larry Oldham

Yes, we have like two-year kickers on the majority of our leases. So when the lease expires within the next couple of years, one to two years, we can kick those out another two years. We picked up a lot of, in some cases, five-year leases, a lot of fours, threes.

Donald Tiffin

The other point to be made, Leo, is this Gate Dancer 2 well that I mentioned earlier is the first 160-acre well that we've drilled. Everything that we've been doing up to that point had been 320acre locations, which, you know, obviously, in New Mexico under field rules we can hold 320 acres with one well.

We can develop two units in that 320 acres. So basically that's been the game plan all along, you know, to go through and drill a bunch of 320s, get a bunch of acreage, HBP, and then go back when the time is right and begin to do 160 acre infill.

Leo Mariani - RBC Capital Markets

And how many wells have you guys drilled at this point in the northern end?

Larry Oldham

Around 24, I believe. That's be 6 by 2 - 6 by 2 would be 12 - times 2 is 24. Fewer than 30.

Operator

Your next question comes from David Snow - Energy Equities.

David Snow - Energy Equities

I couldn't get the slide back up, but what is the net acres in the Barnett including the net acres held in the unleased part of the halo?

Larry Oldham

Well, right now, David, if you take a look at Slide 26, we've got 33,000 gross, 9,800 net acres. That includes our original acreage plus the halo. So today we have about 33,000 gross and 9,800 net acres.

David Snow - Energy Equities

That includes your leased - the unleased halo?

Larry Oldham

That's everything that we have leased as of September 30.

David Snow - Energy Equities

And what is the unleased halo?

Larry Oldham

Well, that's some additional acreage that -

David Snow - Energy Equities

How much is it in acres?

Donald Tiffin

Well, the total potential acreage count in the halo area is about 26,000 acres. And of that 26,000 gross acres, we've leased to this point 11,600 of it.

Larry Oldham

So someday there's an additional 14,000 acres out there that could be leased.

Donald Tiffin

Theoretically available.

Larry Oldham

Theoretically, yes.

David Snow - Energy Equities

Well, is it likely to be, because you're the only game in town?

Larry Oldham

Yes. It'll be a long time before it gets leased because what Chesapeake's doing, they're focusing on their existing leasehold and they're focusing on drilling all their lease obligations which, as you can see, is a multi-year project. So those additional acres in the halo, it'll be a long time before those are drilled or leased.

Donald Tiffin

One thing that's pretty interesting. When you break that 9,800 acres down there's 4,200 acres in the halo, there's 5,600 acres in the floodplain. And the floodplain initially came with some very large acreage tracts, so it's been quite an extensive effort to pick up the halo acres. But in a relatively short time, they've picked up not quite half of the acreage available in the halo.

David Snow - Energy Equities

And they've kind of cut back their leasing of acreage so the remaining in the halo won't be coming into ownership anytime soon?

Larry Oldham

That's correct.

David Snow - Energy Equities

And then the other question is the money market fund that you're putting in the $62 million, is that insured or uninsured? Steve, the money market at Citibank, is that an insured money market?

Steve Foster

No, I think it falls under some of their rates, I think, which are insured for a couple hundred thousand. I think that's about it.

Larry Oldham

Yes. The answer to that, probably not.

Operator

Your next question comes from Patrick Walker - Walker Smith Capital.

Patrick Walker - Walker Smith Capital

The 3D in New Mexico, what's the timing before you'll have that analyzed?

Donald Tiffin

That's a moving target; it always is with 3D. It's one of those things that you know you keep fine tuning and it gets better and better, typically. We're thinking that most of '09, the first half of the year for sure, we're going to be working the 3D. That's another reason why we've moved the New Mexico CapEx back to the fourth quarter.

Now, again, we're quite flexible with that. After the first couple of rounds of interpretation, if something really jumps out at us that we're excited about, then we're going to reserve the right to go ahead and put a rig to work earlier.

Patrick Walker - Walker Smith Capital

And you'd be able to see any [marrow] prospects you'd have on that acreage from the 3D, wouldn't you?

Donald Tiffin

Yes, possibly.

Patrick Walker - Walker Smith Capital

Might you accelerate a drilling plan if you see a couple of good conventional prospects on that 3D?

Larry Oldham

I don't know. I mean, our focus is the Wolfcamp, that fractured regime in the Wolfcamp, and that's our primary focus. And those are shallow wells. You're talking about 5,000 foot wells. Anything below that, you know, you're out there in the - it's wildcat country. You're out in the middle of nowhere. So we're probably going to play it pretty safe, to be quite honest with you, and just focus on the Wolfcamp to begin with.

Donald Tiffin

One thing, if you look at the marrow out there where we're located, I mean, yes, there are a few big fields around, but there are a lot of pretty poor marrow wells, too. Just because you see something that looks like a field doesn't necessarily mean it's going to be something that really turns out to be anything.

Patrick Walker - Walker Smith Capital

Obviously, the operator you've got in the Barnett, it's in their interest to accelerate production as well, so I would assume it's their top priority getting these wells on production. Is that a safe assumption?

Larry Oldham

You know, absolutely. They own 65% of it. Where we are is absolutely some of the best production. It's right in the core and the largest reserves per well. So they are working diligently to get these wells hooked up. They're investing a lot of money in pipeline and gathering. So they're moving ahead and they need the production and cash flow just like we do. So they're not dragging their feet of slow playing anybody. It's just a function of operations and pipelining in that very difficult area inside the city limits.

Donald Tiffin

As often as not when we meet with those guys in Okalahoma City, they'll have more pipeline gas in the room than any other group.

Patrick Walker - Walker Smith Capital

Do I remember that you had something approximately 40 pads - that's the number that sticks with me; I don't remember how many.

Larry Oldham

We've got 75.

Patrick Walker - Walker Smith Capital

75 pad sites?

Larry Oldham

We've got 75 pad sites. How many we think's active, 30 plus?

Donald Tiffin

Somewhere around 30.

Patrick Walker - Walker Smith Capital

So are they between the existing [inaudible] and the 35 that are in process, how many - they're on about 30 different pad sites, that's a guesstimate?

Donald Tiffin

That's plus or minus a few.

Patrick Walker - Walker Smith Capital

And do you have any guess as to how many of those 30 are currently hooked up to pipeline? That's the concerning factor, I assume, right, is when the pipeline makes it to that pad.

Larry Oldham

Yes.

Patrick Walker - Walker Smith Capital

What's your guess as to how many of those are currently hooked up?

Larry Oldham

We're shooting in the dark. I don't want to give you a number because whatever we say is wrong, Patrick.

Operator

Your next question comes from [Neil Four] - Private Investor.

Neil Four - Private Investor

First, in the Barnett, based on the [four] rigs that you say will go on forever looking forward, it looks like we see they have 13 years' worth of drilling going. Do they have the permits for the pads to do that or are they - how far head of them?

Larry Oldham

Yes, we have the pads under control and they're curing leases with a four-rig program. You know, you could drill about 48 to 50 wells a drill. And as the pads get cured up and as infrastructure is developed, I would expect in the right environment that you would see an acceleration of development. But we do not have any idea when that will be, Neil.

You're in an emerging, developing area, and once you get your infrastructure built and you get your pads in place, then you'll get into the manufacturing part of it and then they can accelerate the drilling activities. Right now they're just - they have a four-rig program meeting lease demands, and that's their focus.

Donald Tiffin

The two key restraining factors are the lease situation and the infrastructure, the gathering system. Once you have the gathering system to the pads, once you've got the leasehold secured, then the rest of it moves pretty quickly - the permit process for a well is very quick.

Neil Four - Private Investor

And the Wolfcamp, in your press release, talking about your budget for '09, in the southern area you say that you're going to use that for the acquisition of additional leaseholds and the interpretation of 3D seismic. Can you expand a little bit on the acquisition of additional leasehold?

Donald Tiffin

Well, mainly what we're doing is some of these leases that - and it's not specific to the southern area, it's just in New Mexico in general - but the leasehold, as you can see, it's a relatively small amount and we're basically renewing leases that the kickers are coming into, and in some instances picking up some tracts that we've never owned before. But for the most part, the renewals.

Neil Four - Private Investor

And in the Diamond M, just a little clarification, your '09 budget calls for 21 gross wells. The three that were left over from this year, is that separate or is it going to be 18 plus 3?

Donald Tiffin

It's 18 plus 3 is the right way to look at that. And those 3 that are actually carryover from this year will be drilled in January, February.

Neil Four - Private Investor

If you can put up the slide that was Number 10, apparently you added 400 additional barrels of oil a day to your oil derivatives and I didn't see what they were. Were they collars, were they - the oil derivatives. I guess I have the wrong slide, but it's the oil derivatives slide that shows the '09 2,400 barrels and 2010 2,100.

Larry Oldham

Yes, it's 400 barrels. We put a 400 barrel a day collar on, $75 floor, $94.50 cap. And in 2010 we put 400 barrel a day on with a $70 put - deferred premium put.

Neil Four - Private Investor

Were those two collars - was the collar a costless collar, like the others that you did?

Larry Oldham

Yes. Yes.

Neil Four - Private Investor

Okay, and those $100 puts that you put on last year certainly look great.

Larry Oldham

Hindsight's good, isn't it?

Neil Four - Private Investor

It's too bad you didn't put them on bigger quantities, but hindsight's, you know.

Larry Oldham

Should have put on $140 swaps.

Operator

Your next question comes from Richard Tullis - Capital One Southcoast, Inc.

Richard Tullis - Capital One Southcoast, Inc.

With the recent well costs for the Barnett wells, any more decreases there?

Larry Oldham

It's about $3 million. That's what we're using in our budget.

Richard Tullis - Capital One Southcoast, Inc.

How's the budget split for next year? I know you're spending about $62 million in the Barnett for about 17 net wells. I guess the rest is going for infrastructure and acreage?

Larry Oldham

We're budgeting around $48 to $50 million for drilling and about $12 million for leasehold for a total of about $62 million.

Donald Tiffin

Basically a fifth of it's leaseholds and four-fifth's of it's drilling.

Larry Oldham

What slide is that, Don?

Donald Tiffin

That's Slide 22.

Larry Oldham

Look at Slide 22, if you would pull that up. And there you go.

Donald Tiffin

Yes, $12 million on leasehold, $49.7 on drilling.

Richard Tullis - Capital One Southcoast, Inc.

In your discussions with Chesapeake for drilling next year, you got pretty good assurance from them that they're going to go with the four rigs for at least a good portion of the year?

Donald Tiffin

Yes, they've been very consistent in saying that.

Larry Oldham

That's what they've done for the last two years, and that's what we see now with the drilling schedule that we have from Chesapeake. And that's the best information we have, Richard.

Richard Tullis - Capital One Southcoast, Inc.

With the $118 million in the CapEx budget for next year, what sort of production growth preliminarily do you think you could achieve with that in '09?

Larry Oldham

As you know, Richard, I'd love to answer that question but I can't. We do not give guidance.

Operator

(Operator Instructions) Your next question comes from Unidentified Analyst - Jefferies.

Unidentified Analyst - Jefferies

On that chart that shows the sensitivities, commodity price sensitivities by play, is it then safe to assume that if, let's say the Permian oil properties, that you would not see in your reserve report price-related revisions until we cross those commodity price thresholds?

Donald Tiffin

That's not a good assumption. The reserves are going to fluctuate. The present value's going to fluctuate regardless of whether the price is going up and down, left or right. So, you know, if  yes. I mean, there's - yes, the answer's no. There is going to be some fluctuation regardless of what happens with pricing.

Larry Oldham

Let us pull a slide up to help answer that question. Pull up 14, please. Sabash, if you would, look at Footnote 2. And what we did, we took our June 30 reserves and you notice we had 43.8 million BOE. And then, based on our internally prepared reserve analysis at June 30, we used a $60 per barrel NYMEX of $6 gas. And by doing that we estimate that our total proved reserves would decrease 17% to 36.4 million BOE - a 17% decrease.

Yes, we dropped the oil from, what, $140 a barrel to $60 and gas from $13 to $6.

Donald Tiffin

Yes, oil dropped 57% and gas dropped 54% - I'm sorry, 43% and [46%].

Larry Oldham

So that gives you some disclosure as to what the sensitivity is.

And let me make one other statement. Even at that sensitivity, our borrowing base - based on the information we have today - is still greater than our current $230 million borrowing base.

Donald Tiffin

Just take your question and run with it, though. If you took that plot on Page 21 and if you took that rate of return all the way down to 10% and saw where each project cost 10%. Then, because it's PV 10 basically driven at that point then yes, you could say that those properties would potentially fall off the reserve report.

Richard Tullis - Capital One Southcoast, Inc.

And then in the Barnett, the leasehold budget of $12 million, sort of all the noise now of, you know, $5,000 top lease bids and so on. I mean, do you see a substantial change in lease costs year-over-year?

Larry Oldham

Yes, we do. And at $5,000 an acre, our focus is primarily on any unleased acres in a drilling unit that we may need. If not, we'll drill it without it, and that's where Chesapeake is. It's $5,000 a acre and that's what they're going to pay. It's just a new day in the Barnett Shale.

Richard Tullis - Capital One Southcoast, Inc.

And what do you make of force pooling in the Barnett? Is that going to happen?

Larry Oldham

I don't know. I do not know.

Donald Tiffin

Force pooling has been brought up before the Texas Commission on numerous occasions and has fallen apart every time.

Larry Oldham

I know there's some things happening on it, but I don't know where it's headed. I just don't know.

Operator

And there's no further questions at this time. I would now like to turn the call back over to Larry Oldham, President and CEO.

Larry Oldham

Thank you for attending this conference and we look forward to our fourth quarter '08 conference call, which we anticipate will be in late February or early March of '09.

Again, thank you for attending this conference call and have a great day.

Operator

This concludes the call for today. Have a wonderful day.

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