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Executives

Kevin Nanke - Chief Financial Officer, Treasurer, Chief Financial Officer of DHS Drilling Company, Treasurer of DHS Drilling Company and Director of DHS Drilling Company

Daniel Taylor - Chairman, Member of Audit Committee and Member of Nominating & Governance Committee

Carl Lakey - Chief Executive Officer and Director

Broc Richardson - Vice President of Corporate Development & Investor Relations

Analysts

Evan Templeton - Jefferies Co

Joseph Magner - Macquarie Research

Jeff Davies - Waterstone Capital

Gregg Brody - JP Morgan

Michael Martino

Andrew Shapiro - Lawndale

Delta Petroleum (DPTR) Q4 2010 Earnings Call March 17, 2011 12:00 PM ET

Operator

Hello, and welcome to the Delta Petroleum Year-End 2010 Financial Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Broc Richardson. Please go ahead.

Broc Richardson

Thanks, Amy. Good morning and thank you for joining us for Delta's Fourth Quarter and Year-End 2010 Financial and Operating Results Conference Call. Before we begin, I would like to remind you that we are conducting this call under Safe Harbor, and that this call will include projections and forward-looking statements within the meaning of the Federal Securities laws and are intended to be covered by the Safe Harbor protections. In that regard, you are referred to the cautionary statement displayed on Delta’s website, which is incorporated by reference with respect to the information provided for this call. Investors are urged to consider closely the oil and gas disclosures and the risk factors set forth in Delta’s Form 10-K for fiscal year ended December 31, 2010, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

Today's speakers from Delta are Dan Taylor, Chairman of the Board; Carl Lakey, President and Chief Executive Officer; and Kevin Nanke, Treasurer and Chief Financial Officer.

I will now turn the call over to our Chairman, Dan Taylor.

Daniel Taylor

Thanks, Broc. Good morning, everyone, and thank you for joining us today. On this call, management and I will not just discuss the fourth quarter and 2010 annual results, we will highlight the goals we set for Delta in 2010 and the accomplishments we achieved in the latter part of the year. We will also explain how we intend to carry these achievements forward in 2011 and what that means for our shareholders.

Contemporaneous with the appointment of Carl as our CEO in the summer of last year, the Board outlined several objectives to be achieved for the remainder of 2010. We communicated this to you in our prior conference calls. They were the simplification of our asset base through the sale of non-core assets, the reduction of operating and overhead cost, the improvement of Vega Area's per well reserves and economics and the obtaining of a new senior secured credit facility.

We achieved all of these objectives, and Carl and Kevin will take you through each of them. These accomplishments are noteworthy and of great value to Delta, particularly in the current gas price environment. Going into 2011, these operational improvements will have a very positive effect on Delta's direction, strategy and asset value. For this year, our objectives are to maintain the cost improvements we achieved in the fourth quarter, to quantify any additional reserve upside in the deeper zones of the Vega Area, to solidify our acreage position in the Vega Area, to maintain an operational focus on our core asset and to reduce our financial leverage and improve liquidity. The execution of these objectives will ensure that we realize our ultimate goal of continuing to improve our asset value in the current commodity price environment and creating value for our shareholders.

I'm sure many of you have heard or read the response of noteworthy CEOs of other E&P companies that have expressed their research, reviews and forecast of the North American natural gas market. While we generally share these predictions of the recovery of natural gas prices, we view it is our responsibility to help Delta prosper in the current natural gas market environment and not to simply survive until the recovery occurs. We have taken some meaningful concrete steps in that direction and will continue to do so in 2011.

Carl and the rest of the management team have shown the Board that they are fully capable of achieving the strategic objectives for 2011. The management team and the company have the full support and backing of its largest shareholder, Tracinda Corporation. We are anticipating a promising year in 2011.

I will now turn the call over to Carl for his comments. Carl?

Carl Lakey

Thank you, Dan. We certainly recognize and appreciate Tracinda's continued support of Delta. I also believe 2011 will be a promising and transformative year for the company. With regard to the objectives we achieved in 2010, I will first address the simplification of our asset base, which now consists of the Vega Area, of the Piceance Basin and interest in other fields, which are non-operated. This simplification allows us to retain a smaller workforce that is focused on one thing: the efficient management and operations of the Vega Area. An important element of this focus is the associated reduction in Delta's stand-alone cash G&A expense as evidenced by Q4 2010, which was 43% lower than the run rate in the first half of 2010.

We remain focused on managing our G&A expense, and we'll seek to implement further reductions in the future. Not only did we see significant reductions in our G&A expenses, but we also achieved meaningful 38% quarterly improvement in our lease operating expense in Q4, which is now at $1.09 per Mcfe for continuing operations. Much of this LOE savings is attributed to low production and water disposal cost. We had substantial completion activity in the fourth quarter, and were able to reuse our produced water and completions rather than having to pay for disposal. Going forward, we anticipate sustaining our water disposal costs at their decreased level even as completion activity decreases in the current quarter.

This is due in large part to a shift in water disposal methods to subsurface injection. We will be utilizing existing wells that have negligible or no production and which will be converted to water disposal wells. We expect to have three wells permitted in Q1 for water disposal and five by the end of Q2 to meet our anticipated water disposal needs.

While the improvement in our cost structure of both G&A and LOE have greatly improved the operational profitability of the Vega Area, we've also been working on the revenue side of the property equation. We are excited to report both increased production and improved recovery of reserves per well. Our per well EUR is improved by 39% to an audited 1.6 Bcfe gross using the new Gen IV stimulation techniques versus the prior methodology. I believe the best indication of the significance of this change is that 16 wells or 8% of the total wells in the Vega Area are now producing 39% of the field's total production. The incremental completion cost is approximately $500,000 per well yielded a drilling and completion cost of $2.4 million per well, which we feel we can decrease to $2.1 million with a more continuous development program.

Delta net production for December was 21% higher at 38.9 million cubic feet equivalent per day than September 2010 net production. This increase was driven by the completion activity of the inventory wells using the new stimulation technique, which increased Vega production by 34% over the same period.

We are also pleased to share that we expect the production improvement to continue into Q1 2011 with an additional 4% to 7% of production growth. Perhaps most significant is that this improvement now points to an increase in total proved and probable reserves in the Williams Fork in the Vega Area of a net 2.9 Tcfe, up from 2.1 Tcfe based on strip pricing. As we mentioned in the third quarter's call, we began drilling a well targeting additional deeper formations, which had indicated to be productive in recently drilled wells by other operators in the Piceance Basin. In fact, there are now 62 active permits with the Colorado Oil and Gas Conservation Commission filed by our competitors in Mesa County and the surrounding three counties that target deeper formations, including the Mancos, Niobrara and Frontier.

Multiple wells by other operators in Mesa County have reported initial production rate to the Colorado Oil and Gas Conservation Commission that are in excess of 6 million cubic feet a day. These production rates and volume of activity in the basin of what interested us in testing the deeper formations. We reached a total depth of 13,300 feet in mid-December with that well. Technical evaluation and completions design work combined with a timing parallel cement cleanout and prepping of the wellbore between fluids took us through January. Stimulation activities started in mid-February through the availability of crudes. Between the second and third fracture stages, a downhole wireline tool became stuck in the wellbore. Much of that tool has been removed from the wellbore, but efforts are still underway to retrieve the last components of the tool. There is always some risk associated with these types of events , but we feel that the plug will be recovered and that normal completion activity will resume shortly.

We expect that our completion activity will take us through most if not all of the month of May. The shows we experienced while drilling and the electrical logs both indicate that we have 3,700 feet of gross prospective interval in these deeper formations but clearly nothing will be conclusive until production occurs. Due to the information gathered from our well and other third-party wells in the area, we began drilling another well in the Vega Area, which we'll drill slightly deeper than the Williams Fork into the Mancos formation. The Mancos was one of the two formations on our deep test well that exhibited the best shows and appear to be the most prospective. Of course, our objective is to lower our per well finding and development costs by accessing more economically productive zones. When combined with our lower lease operating expense, we hope to improve the profitability of the development and production in the Vega Area. We will publicly disclose the results of the deep test well and the new Mancos well when it's appropriate to do so.

Dan mentioned several goals for 2011 upon which management will be focused. One of those goals is to solidify Delta's acreage position in the Vega Area as cost effectively as possible. I'm pleased to report significant progress has already been made in this regard. At the beginning of 2010, Delta had 81% of its acreage held by production and 3,600 acres that were at risk of expiration before 2013. Delta expects, based on work already accomplished and the drilling of one leasehold well in May 2011, that we will then have 93% of the acreage converted to HBP or Held by Production and only 740 acres under threat of expiration before 2013.

Taken collectively, our back to the basics approach to business has helped Delta lower its cost structure, increase production, improve per well recoveries, decrease finding and development cost and has the yet unknown potential of improving on that further if the deep wells are proven productive. In conclusion, we are pleased to present to our shareholders the results of improved fourth quarter that demonstrates clear operational achievements and the resulting substantial improvement in our financial performance. Coupled with the plan for 2011, we believe we are well positioned to enhance shareholder value if we execute. And I'm confident we will.

I'll now turn the call over to Kevin for his comments on our financials.

Kevin Nanke

Thank you, Carl. Good morning. For the quarter, we reported production from continuing operations of 3.35 Bcfe, which falls within the production guidance range we provided of 3.25 to 3.55 Bcfe and was a 7% increase from the previous quarter pro forma adjusted for the divestiture in July. EBITDAX for the fourth quarter was $10.4 million, a 20% increase from the third quarter. EBITDAX for the full year 2010 was $36.5 million, an 85% increase from 2009 levels. It should be noted that our EBITDAX increased over third quarter and full year despite production declines from asset sales.

Our lease operating expense per Mcfe from continuing operations decreased 38% from the third quarter. The significant decrease is primarily attributed to lower water disposal costs in the Vega Area due to the completion activity we performed in the quarter as Carl mentioned. Our completion activity is scheduled to finish within the next several weeks. We anticipate maintaining these lower lease operating costs utilizing water disposal wells. Transportation costs increased in total dollars and on a per unit basis by approximately 20%. This increase was primarily due to our increased production in the Vega Area where we extract the liquids through a processing plant providing us with favorable pricing.

Our natural gas liquids or NGLs, currently represent approximately 20% of our revenue from the Vega Area. To put this number in context, the extraction of the NGLs from our gas stream only reduces our MMBTu content by 10% to 15%. And the current prices of the NGLs are far in excess of what the revenues would be if we kept within the gas production. This is evidenced by our realized price per Mcf. In the fourth quarter, our blended realized price was $4.66 per Mcf, whereas the average Henry Hub spot gas price for the fourth quarter was only $3.80.

Moreover our realized price also included the differential of Henry Hub to CIG, and of that, a negative $0.40 for the quarter. Subsequent to year end, we entered into new NGL hedges. With those hedges in place, we anticipate this favorable pricing to continue. Production taxes in fourth quarter were unusually low as a result of updated prior period estimates and are not reflective of our expected run rate of 4% to 5% of oil and gas revenue.

We reduced our G&A to $7.8 million for the fourth quarter, of which $2.7 million was noncash equity compensation, and $1.1 million was G&A for DHS. This equates to a Delta stand-alone cash G&A for the fourth quarter of approximately $4 million.

So while the quarter's total G&A was lower in the third quarter by 25%, the cash component of G&A for Delta stand-alone was lower by 33%. It's worth noting that the G&A in the third quarter did include nonrecurring items such as severance costs associated with our personnel reduction, as well as a $1.4 million DHS bad debt write-off that was discussed on our last conference call. We are pleased with the reduction in overhead we have achieved to date. Our credit agreement requires us to stay focused. We project Delta stand-alone cash G&A to approximate $4.5 million a quarter for 2011 and hope to improve on that. We are currently marketing DHS for sale. We believe we have sufficient access to rigs and that the sale of DHS will not affect our Piceance development.

As detailed in our press release yesterday afternoon, we announced our 2010 reserves, which shows the improvements in our EURs and lower operating cost. Total proved reserves at December 31, 2010 were 134 Bcfe using SEC pricing requirements, an increase of 17% from the prior year proved when adjusted for the 39 Bcfs sold in the third quarter. 91% of our reserves were natural gas, which include related natural gas liquids and were 92% proved developed. Our production replacement rate totals 218%.

I think it is important to place our proved reserves in proper context. So I'd like to provide you with a couple of price sensitivities. Using the pricing from the natural gas forward curve as of year end and limiting ourselves to locations that meet the five-year drilling requirement on a four rig drilling program, our proved reserves increased to 767 Bcfe with a standardized measure of $528 million. With an additional $1 per MMBTu increase in natural gas price, our standardized measure increases to $873 million. The total estimated recovery from our Vega Area asset is now 2.9 Tcfe. These reserves do not consider additional potential from deeper formations beneath the Williams Fork section that we're currently testing. Earlier this week, we announced our credit agreement with Macquarie. The amendment provides for nearly $19 million of additional liquidity under the term loan portion of the credit facility. The new facility removes the development plan approval process and mandatory cash flow suite repayment requirement. With full access to the $25 million term loan, we have sufficient liquidity for 2011 to evaluate the deep potential beneath the Williams Fork. We also project full covenant compliance for the duration of the facility.

Our 2011 drilling and completion capital budget for the Vega Area has not yet been determined beyond the two exploratory test wells, lease preservation well and five drilled but not yet completed inventory wells. Once we have sufficient results from the exploratory test wells, we will update our 2011 capital budget. In conclusion, we are pleased with the progress we achieved this quarter and fully expect to maintain these financial improvements and translate them into a solid trend going forward. With that, we will open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Andrew Shapiro at Lawndale Capital Management.

Andrew Shapiro - Lawndale

Could you give us or update us a little bit more on the status of the sale of DHS, like the expected milestones and potential timing of those milestones? And how much influence and control does Delta have over the sales process? I'm not sure exactly your ownership percentage of DHS.

Kevin Nanke

Yes, we just engaged Macquarie to help us with that process. We did that, I believe, a couple weeks ago. It's fairly early into that process obviously, but we don't believe that it will take a long period of time to get through it. Delta owns 49% of DHS. So we obviously have a significant influence of the outcome of that transaction.

Daniel Taylor

This is Dan. In addition, I'd like to point out, our partner, Chesapeake Energy and DHS fully supports this process as well. And we will be working closely with Macquarie to move it forward quickly. You should be aware that we do not expect to receive meaningful proceeds from the sale of the company. However, all of the nonrecourse debt that's currently reflected on our balance sheet will disappear as part of this transaction.

Andrew Shapiro - Lawndale

Right. And that led me to this follow-up question regarding this. Is there a -- on the balance sheet of Delta, which you -- I guess you consolidate DHS into this?

Kevin Nanke

Right.

Andrew Shapiro - Lawndale

And if so, what is the negative net worth that's been consolidated into DHS or the positive shareholder equity in that number that is consolidated into Delta's balance sheet?

Kevin Nanke

Well, as we sit today, we actually have a negative equity position in DHS. So if you would assume that you would have a zero value for this transaction, we'd actually still report a gain once we close this particular transaction.

Andrew Shapiro - Lawndale

Right. And as of December 31, what's that negative net worth? What would that in essence -- that gain be, you sold it for zero for Delta.

Kevin Nanke

Approximately $2.5 million.

Andrew Shapiro - Lawndale

Okay, and last question, separate issue, with increased environmental concerns from frac drilling, and you are mentioned here of a new water disposal method, could you just clarify or explain the new water disposal methods? And then to the extent this is a riskier or less riskier method of disposal, with respect to, I think it's mostly water pollution concerns from frac drilling.

Carl Lakey

Certainly. Andrew, this is Carl Lakey. The subsurface water injection is actually a very well time proven technique, broadly used across the industry to dispose a produced water. The oversight of that is provided by the Colorado Oil and Gas Commission, which permits and monitors those activities with strict compliance into subsurface aquifers that are not related to aquifers that supply drinking waters or fresh water for agriculture. So there is no mixing or blending of waters that would be used for beneficial purpose. And so therefore, we feel very comfortable with the risk profile associated with that.

Operator

The next question comes from Mike Martino at Wedbush.

Michael Martino

Can you give us some clarity on the deep well testing? Any idea on the IT or the EBR and the value it would add?

Carl Lakey

This is Carl. Mike, certainly the value question is difficult to ascertain yet from our well, given that we don't have production rates to surface yet. Probably the best analog I can provide for you is that it's been published in public documents with the Colorado Oil and Gas Commission where we've seen IP rates in the 6 million and 7 million cubic feet a day in neighboring areas in Mesa County, published by other operators. We're certainly encouraged with what we've seen, but we can't comment yet on what the expected value would be or what our rates will be until we have them.

Michael Martino

If they are successful, does it translate to the entire area?

Carl Lakey

We believe it will translate to the area, yes.

Operator

The next question comes from Joe Magner at Macquarie.

Joseph Magner - Macquarie Research

Just a little more on these deep wells, can you go into just the cost comparison to your Williams Fork wells?

Carl Lakey

Okay. Williams Fork well is roughly we've talked about $2.4 million and under a continuous development scenario being able to get that down to about $2.1 million. Our current deep well, we expect we'll spend about $10 million on. And we would expect in a forward case, given what we've learned and the amount of -- that well have tremendous amount of science in it and a lot of learning on our part, we would expect to be able to get down in the $7 million to $8 million on subsequent attempts.

Joseph Magner - Macquarie Research

Okay, so I guess -- and then what's the typical IP rate now under this new frac technique?

Carl Lakey

In the Williams Fork, the new frac technique, these things tend to IP between 1.7 million and 2 million cubic feet a day.

Joseph Magner - Macquarie Research

Okay, so I guess it's about a 4x improvement in the rate for a cost that's roughly 4x your current cost? Well, if you're using the 2.4 million versus the 10 million comparison, is that...

Carl Lakey

Well, I think we're perhaps mixing projects here. The rates that I just quoted are for Williams Fork wells, not for the deeper shale wells.

Joseph Magner - Macquarie Research

No, I understand. I'm just comparing, if you're saying 1.5 million, 1.6 million and then that compares to some of the IP rates that have been seen by some operators of 6 million to 7 million, that's what I was...

Carl Lakey

Mixed zones, I'm sorry. I don't believe that's accurate.

Joseph Magner - Macquarie Research

I guess what I'm trying to ascertain is just the driver of what is taking you away from your bread and butter Williams Fork, 2.9 Ts of probable upside, activity that could drive some production and cash flow versus spending $10 million of liquidity that's pretty dear at this point on a deeper exploration target. That's what I'm just trying to...

Carl Lakey

Well, I think obviously we believe that there is the chance of lowering our F&D cost even further. By the time you get done with bolting on that deeper production to potentially a Williams Fork well. And that's the driver is to understand, if we can do that.

Joseph Magner - Macquarie Research

And these are zones that you think could be commingled?

Carl Lakey

Certainly, our expectation on the second well that we're doing is to try and do exactly that, either commingle or dual complete.

Joseph Magner - Macquarie Research

Carl, why don't you mention the cost underneath just the second deep, which is considerably less than...

Carl Lakey

Yes, the second deep which is targeting the Mancos is right now AFE'd [authorized for expenditure] at about $4.8 million.

Daniel Taylor

Now remember for the cost of both of those wells, that's total cost not incremental cost over what it takes for the Williams Fork.

Carl Lakey

That's correct.

Joseph Magner - Macquarie Research

Okay, so there'd be some incremental completion cost for the Williams Fork if you were to drill deeper, but it wouldn't be a full on new…

Daniel Taylor

Well the $7 million to $8 million would be all inclusive.

Joseph Magner - Macquarie Research

The Williams Fork completion as well?

Daniel Taylor

Correct.

Joseph Magner - Macquarie Research

Okay. And a question on, you highlight 2.9 Ts of probable upside, and then it looks like in your new future development capital category, you're only assuming about two years of development. Did I read that correctly? I'm just curious, is that a capital limitation mainly, or what would I guess keep you from putting more development capital into your assumptions and expectations? If you do have that 2.9 Ts probable upside in the Williams Fork?

Kevin Nanke

You're right. We're not limited in the amount of capital we could spend or someone else could spend. What we provided was a sensitivity that really kind of stayed within the SEC drilling five year drilling rules, which we assumed a four rig drilling program and just the number of wells that we could possibly drill within those five years.

Carl Lakey

And I think equally important that within that period of time, you still only really made a dent in that total of 2.9 Ts. You haven't fully developed it at all.

Joseph Magner - Macquarie Research

Right, no, I appreciate that. I was just curious what the driver was, but I guess it's a...

Daniel Taylor

We felt the most reasonable approach was to assume that we ramped up the four rigs over time in doing those calculations. Obviously, that could vary considerably depending on conditions and the economy and everything else.

Joseph Magner - Macquarie Research

Okay. But can you provide us any more information on the sort of Gen IV frac, has that evolved from the other improvements you've made over the past, I don't know, 18 to 24 months, and kind of what the main characteristics of what you're doing now are?

Carl Lakey

Okay. Well, the Gen IV frac, just to provide a little bit of clarity around it. And I'd just as soon not get into a tremendous amount of public detail, because obviously it's something we're proud of and don't necessarily need replicated. It's a larger frac. It is done with slick water, produced water and it uses very low sand concentrations, higher rates and staging designed to increase fracture complexity.

Operator

The next question comes from Evan Templeton at Jefferies.

Evan Templeton - Jefferies Co

First of all, just another follow-up on the deep well, do you anticipate seeing, will that be dry gas or do you expect a fair dose of liquids associated with that also?

Carl Lakey

I think our expectation going in is dry gas. We wouldn't be disappointed at all to see some liquids out of it, if that's what ultimately comes. But I think you'd have to say the expectation is dry gas.

Evan Templeton - Jefferies Co

Okay. And then just a second point, I was hoping you could maybe help me understand. In terms of the reserve additions this year, the extensions category, so is that basically just a result of applying the increased IPs, increased recoveries from this Gen IV frac to your inventory?

Carl Lakey

In a word, yes.

Evan Templeton - Jefferies Co

And how many wells have you applied the Gen IV frac to so far?

Carl Lakey

I think it was 16 is what we reported.

Operator

The next question comes from Jeff Davies at Waterstone Capital.

Jeff Davies - Waterstone Capital

Sorry if I missed this, but what's the full year CapEx budget?

Kevin Nanke

We have not provided a 2011 CapEx budget at this time.

Jeff Davies - Waterstone Capital

Okay. And then can you just remind me in Vega of what you have for processing and pipeline capacity?

Carl Lakey

Okay. Multiple answers here because there's what Delta has and its equipment. We have currently on the ground compression equipment able to move 60 million cubic feet a day into the pipeline. The pipeline is the sales pipeline, midstream pipeline is a 24-inch line that has the capacity ultimately to move 600 million cubic feet a day of gas between us and our neighbors, Occidental and some other smaller operators in the valley up to the Meeker Plant. So there is ample takeaway capacity out of the Vega Area. Our compressor station at 60 million a day is permitted and able to bolt on additional compressors to move that number to 120 million cubic feet a day with permits we already have in hand.

Jeff Davies - Waterstone Capital

Okay. And I kind of appreciate you guys clearly focusing on operations, good to see the LOE numbers coming down here little bit. But operationally, I'd like to say, good to see the focus but financially, still have a couple looming maturities. I'm just kind of curious what your thoughts are and specifically the convert put next year?

Kevin Nanke

Well, clearly, we recognize that the put is out there. The results of the deep test will, I guess, provide us with additional information to kind of refocus on how we're going to take care of that. And we probably won't comment on that until we have the results from the deep test.

Jeff Davies - Waterstone Capital

Okay. So not to put words in your mouth, but you're hope is you can prove that up and monetize?

Daniel Taylor

Yes. This is Dan. Just to provide some additional color. Obviously, Carl, Kevin and the team successfully completed an amendment to our credit agreement, which gives us runway for the rest of 2011. That will give us plenty of time to find out what we have in these deeper zones. Conversely, with the improvements that we made in the existing asset, we believe that there is a shareholder value that's been created during this process. And we believe that the company will have options regardless of the outcome. But we have time to evaluate and make sure that we maximize those options.

Carl Lakey

Agreed. I would add just one other thing. I think that certainly the deep wells are something that could be accretive, but we haven't lost sight on the fact that our bread and butter is still Williams Fork, and we've made meaningful improvements there that add value to our shareholders and do create additional options.

Jeff Davies - Waterstone Capital

Okay, but I guess on the press release you talk about G&A being lower because no longer in the strategic review process. But at some point, you're going to have to pick up an advisor again here to explore some of these options, I would assume.

Carl Lakey

I think all options are still on the table for us right now, yes.

Operator

[Operator Instructions] Our next question comes from Andrew Shapiro at Lawndale Capital Management.

Andrew Shapiro - Lawndale

It's a little follow-up here on the financing. Can you go through or just summarize here the current state of and quantity of the financing as recently amended, their upcoming maturities, any springing puts, et cetera? And I think, coming from that is a follow-up question, which is if you have these puts on the converts in the middle of 2012 and the current senior debt's due in the early 2012, do you feel it is necessary to deal with the converts or have something refinancing on those converts in order to get a new senior debt deal in January?

Kevin Nanke

This is Kevin. I'll go through the current credit agreement and answer those questions. We're not in a position to discuss anything relating to the converts at this time. I think we made that fairly clear. The current credit facility is, I guess where we sit today, we have a little over $25 million and I think it's like $26.5 million of liquidity as we sit today under our credit facility. The trigger points, there really are no trigger points as long as we stay focused and don't violate the agreement and go into default, which we project that we have no issues with that going forward. And then I think that's pretty much what you asked.

Daniel Taylor

With respect to the puts coming due in the middle of next year and our current credit agreement maturing in January of next year, as we said, we are considering many options, and we believe that we have plenty of time to execute successfully. And we believe that whether or not these new wells come in, we will execute successfully. We're just not prepared at this time to be discussing those options.

Operator

Our next question comes from Gregg Brody at JPMorgan.

Gregg Brody - JP Morgan

Just you mentioned you weren't providing a 2011 CapEx budget yet, but I was wondering if you could give some details around the wells you said you were going to drill this year? In terms of the completion, how much that would cost, and just on the five wells you plan on completing...

Carl Lakey

Okay, so Gregg, this is Carl, and I'll try and walk you through what I would call our base case for CapEx, and this is really the activity that is either in process or currently contemplated. Of the five inventory wells we had at the end of the year, we've actually completed three of them already. We have two yet in front of us to complete. And those completions should run somewhere between $1.2 million and $1.4 million per, to do the fracs and the Gen IV and the facility hookup in the Williams Fork wells. We also have the deep well that's all the way down at 13.3 that we have to complete as well as the Mancos test well in front of us to complete. And then finally, we have a lease preservation well that we'll be drilling in May to help solidify some acreage up in the Northeast part of our leasehold. And that really concludes the bulk of the currently contemplated activity. Obviously results of those could create changes in our capital expected beyond that, but at least right now, that's what's currently on the plate.

Gregg Brody - JP Morgan

Most of that sounds like the first quarter and some second quarter, is that right?

Carl Lakey

Yes, that's correct.

Gregg Brody - JP Morgan

And then just the cost of drilling the water disposal wells, how much would that cost you?

Carl Lakey

Well the conversions of the disposal wells are going to be about $250,000 per, and we're going to do four of those. We may or may not have to drill a disposal well. And if we did, it wouldn't be -- $1 million is a reasonable number, could be less, but that's a good number.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Carl Lakey for any closing remarks.

Carl Lakey

Thank you very much for attending our conference call. As you can see, we're pleased with the operational performance that Delta is showing. And we look forward to speaking with you again. Thank you.

Operator

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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