Particle Drilling 8-K Results of Operations and Financial Condition

Exhibit 99.2

PARTICLE DRILLING TECHNOLOGIES, INC., #11066858

Third Quarter Earnings Conference

August 9, 2006, 10:00 a.m. ET

Chairperson: Jack Lascar

Operator	Good morning, ladies and gentlemen, thank you for standing by and welcome to the Particle Drilling third quarter earnings conference call. At this time, all participants are in a listen-only mode. Following today’s presentation, instructions will be given for the question and answer session. If anyone needs assistance at any time during the conference, please press the star followed by the zero. As a reminder, this conference is being recorded today, Wednesday, August 8, 2006.
	I would now like to turn the conference over to Jack Lascar. Please go ahead, sir.
J. Lascar	Thank you, Steven, and good morning, everyone. We appreciate you joining us for Particle Drilling Technologies’ conference call to review its quarterly results and the operational performance of its particle impact drilling system.
	Before we begin, I have a couple of housekeeping items I would like to go over. If you would like to be on our email distribution list to receive future news releases, please call us at DRG&E and relay that information to our office. That number is 713-529-6600. An archive of this call will be available later this morning on the investor relations section of the company’s website at www.particledrilling.com. A telephonic replay of the conference call will be available through August 16, 2006. Access details were provided in yesterday’s press release.
	Please note that the information recorded on this call speaks only as of today, August 9, 2006, therefore time sensitive information may no longer be accurate as of the date of any replay.
	The discussion today may contain forward-looking information that is based upon management’s beliefs as well as assumptions made by and information currently available to management. Although the company believes that the expectations reflected in such forward-looking statements are reasonable, the expectations are subject to numerous uncertainties and management can provide no assurance that such expectations will prove to have been correct. Important risks and uncertainties could cause actual results to differ materially from those described in any forward-looking information provided during the discussion today. Such risks and uncertainties may include but are not limited to Particle Drilling’s ability to raise equity capital if necessary and its ability to obtain equity financing on acceptable terms if at all, a severe worldwide slowdown in the energy services sector, working

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	capital constraints and other risks described in the company’s filings with the Securities and Exchange Commission.
	Further, Particle Drilling is a development stage company that operates in an industry sector where security values are highly volatile and may be influenced by economic and other factors beyond the company’s control such as announcements by competitors and service providers.
	I would like to turn the call over now Jim Terry, Particle Drilling’s Chief Executive Officer. Jim.
J. Terry	Good morning, ladies and gentlemen, and thank you for taking the time to listen to this call and for your continued interest and support of our company.
	Today I have with me Chris Boswell, our Senior Vice President and CFO; Tommy Hardisty, our Senior Vice President in Charge of Business Development, and our newest member, Greg Galloway who’s our VP of Operations and Engineering.
	I’ll start with a little history about the events that drove our priorities for Q3, explain the results of those activities and then discuss our objectives and expectations for Q4. Following that, Chris Boswell will discuss Q3 financial results and then we’ll open it up to questions from the audience.
	By way of explanation, there are 3 major components of the particle impact drilling system. The downhole component which is comprised of the sized steel particles which exit the special PID drill bit at high velocity to fracture the rock in front of the bit; this being the most important component and feature of the system.
	The other two components are on the surface and act in support of the PID bit. The first component injects the steel particles into the drilling fluid to feed the PID bit and the second extracts and processes them for reinjection, thus completing the cycle.
	To date, the vast majority of our research, development and testing efforts have been applied to the downhole portion of the system. We achieved several milestones in the first commercial trial which was completed as you know in May.
	The single greatest achievement of the first well was the confirmation that the system’s drilling performance measured as the rate at which the drill bit penetrates the rock exceeded our calculated expectations at depths greater than ever attempted before. This confirmed that drilling with particles and the physics of how it works to remove the hard rock works at depths over 10,000 feet in a live well environment and at rates of at least 3 times faster

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than conventional bits does indeed work. In fact, instantaneous penetration rate improvements of 300% to 600% were achieved on this well.

When I joined the company in late January of this year there were still uncertainties about system performance at depth, particularly with regard to the surface components. There was a lot of information available with results of previous testing activities both at Terratec and Catoosa but the test work was performed at shallow depths in more of a laboratory environment than would be encountered on a live well drilling at depth.

The fact is that some of the test data can and was extrapolated to real well environments but not all variables lend themselves to reliable results when based upon extrapolation. Quite simply, you can’t know what you don’t know and some things can only be learned in live well environments. Consequently, we were not surprised to have learned new things from the first trial. In fact we expected it. We were, however, surprised that the solutions to component improvements were relatively straightforward, readily available and easily implemented.

Having said all that, our conclusion is that the second most important achievement on the first well was the learning that could only take place on a live well at depth, running in conjunction with a standard drilling rig. The opportunity to operate the PID system for over a week also provided us with a very large and relevant dataset we had not had previously. The analysis of this data, combined with observations made during the drilling of the well, made clear what areas of the system worked well and identified areas that required improvements.

Our efforts following the completion of the first commercial trial have focused on the improvements required prior to conducting the second commercial trial. We are now days away from mobilizing for the second field trial so I’ll take some time explaining specific modifications we’ve made to the PID system.

While we have made some modifications and improvements to the downhole PID bit, the majority of our effort has been directed to the surface component that extracts the steel particles from the drilling fluid. This surface component was responsible for nearly 90% of the particle drilling downtime associated with the first well. In pervious testing this component functioned properly but its weakness was exposed due to the increased volumetrics and other variables associated with drilling a well 5 times deeper than any previous testing of that component.

We have replaced the particle extraction component which was located in the flow line with a more straightforward and simple particle recovery method utilizing near off-the-shelf components available from outside the oil service industry. These components include a rotating drum magnet, a

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demagnetizer and a belt conveyor. With these changes we have moved the process of extracting the steel particles from the drilling rig’s return line to the downstream side of the rig shale shaker.

Some of the advantages of doing this include easier adaptability to any drilling rig, moving from a pressured environment to one at atmospheric pressures and running an opened versus a closed system to facilitate the inspection and maintenance without interruption of any of the normal rig operations. With this change we are confident that the performance of the new process will exceed our current requirements and those we expect to encounter on wells drilled with significantly greater depth in the future.

To recap, the most critical element of the system, this downhole PID bit, exceeded our performance expectations but we took the opportunity to make some subtle enhancements that should extend the life of the PID bit.

The particle injection system worked well with minor exceptions and those exceptions have been addressed. The particle extraction system was responsible for 90% of our PID downtime and this has been completely replaced and a new system has been tested based upon the live well requirements observed from the last well.

We’ve also spent a considerable amount of time and effort analyzing and revising our operations procedures to ensure compatibility with the standard operating procedures of the drilling rig.

Looking a little more forward to the future, we continue to make good progress on the new particle injector system. We’ve now assembled the first canister and will begin testing of that system in the next 2 weeks. We will know more after early testing but our current plans call for continued to near term reliance on the proven frac pump based 2-stage injector we’ve used for all previous work.

In anticipation of reaching revenue stage in order to begin ramping the business, our Board of Directors recently authorized the construction of a second PID unit. The new PID unit will be outfitted with the latest equipment upgrades and system improvements and should be ready for operations in December of this year.

We’re very excited about this progress. We’re confident these changes will allow us to drill more continuously, resulting in much longer footage run and give us a very good shot at reaching the revenue stage. Further, we believe the modifications and efficiencies being made will substantially improve our ability to ramp up the business more rapidly.

The reason for that is many of our new components, including our new injector system, once fully developed are being found outside the oil patch.

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	Backlogs for traditional oilfield service equipment are now an industry-wide problem whereas we believe the majority of the new equipment will not be subjected to these delays.
	We continue to be pleased with the amount of demand in the industry for the PID technology. A number of potential customers have expressed strong interest in PID trials on their wells. Because we only had 1 PID unit, we’ve deferred those conversations but continue to maintain dialogue with them as to our progress.
	While we remain focused on building our presence in the North American market, we’ve received inquiries from E&P companies in the Eastern Hemisphere and some large oilfield service companies about providing this service in international markets.
	As I indicated in our last conference call, we continue to discuss commercial and operational aspects of granting exclusivity to the PID technology in particular countries outside the U.S. We view this as a building block for our future but don’t expect it to result in any drilling outside the USA for 10 to 15 months.
	As you know, our next commercial trial will be performed in the Uinta Basin in northeastern Utah where there’s a considerably large market for our drilling technology. We expect to be moving our equipment and personnel to the drilling location some time in the next week and begin drilling operations some time later this month.
	Nobody in this business would expect to deploy a fully implemented new technology on the first well and come away with having learned all there was to learn. We were very good students on the first well and we’ve studied and practiced a lot since then. We are very confident that we’re now prepared to take the test and that the results will be savings for our customer and our first revenue.
	With that I’d like to turn it over to Chris Boswell to discuss our financial results.
C. Boswell	Thanks, Jim. The third quarter, as we communicated in the last conference call, looked a whole lot like the previous quarter. We lost 11 cents per share and we would expect that number to decrease some as we go into the fourth quarter just due to lower direct R&D costs and because we’re expecting better test results on the second well.
	In the first quarter of this year, our spending levels increased because of the Catoosa test which added approximately $400,000 to the quarterly spend. The second quarter our cost levels were high because of the large amount of expenditures on the new injector development, fairly significant legal costs

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associated with litigation and accruals related to our incentive bonus plan that was adopted in the second quarter of this year.

In the third quarter our cost levels were again higher due to the Gasco test, the first commercial trial and the associated costs as well as continued development of our injector and the incentive bonus plans that I just discussed.

For the fourth quarter as we look forward, we would expect a lower loss than any previous quarter driven by the near term completion of the injector development, settlement of the litigation. Furthermore, a successful second trial would avoid a high cost of the second test.

As I stated in the last conference call, we maintain a reasonable level of liquidity and hope to get 2 PID systems deployed later this calendar year which should allow us the opportunity to generate sufficient cash flow to cover our fixed costs. Based on our gain sharing model and given the rate of penetration gains that we’ve observed during the test work, the achievement of positive cash flow would only require us to perform 2 successful jobs per month with each PID unit.

When we begin to generate revenues and cash flow from operations, we believe additional sources of capital will be available to us to assist in the company’s growth including the licensing arrangements Jim discussed a few minutes ago, eventual bank financing and other alternatives.

In order to better understand our cost levels for the first 9 months of this year, I’d like to quickly review some of the major cash cost components, or overall components that is.

For the first 9 months of the year we incurred operating costs of approximately $8 million. This cost level included deprecation expenses of $504,000, non-cash compensation expense of $1,431,000 and non-cash bonus accruals of $551,000. Therefore the cash operating expense for the first 9 months is approximately $5.5 million. Included in this $5.5 million, however, is approximately $2 million related to specific R&D projects such as the design and manufacturing of the new particle injector prototype, several of them actually, manufacturing and testing of PID drill bits, testing of the PID system at Catoosa, testing the PID system on the first Gasco well as well as supplies, parts and tools that are used on future Gasco wells.

Thus, for the first 9 months of the year our fixed operating cash cost excluding independent R&D projects was roughly $3.5 million. This translates into $4.7 million on an annualized basis in terms of cash utilization.

Direct R&D expenditures going forward will be limited to specific projects

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	that will be approved by management. In the next 6 months or so we anticipate spending approximately $400,000 on specific R&D projects. Further, our Board has approved the assembly of a second PID unit which is estimated to cost approximately $1.6 million.
	Based on this spending level, the $5.1 million in cash and short term investments that we currently have on the balance sheet we believe is sufficient to fund our operations into the second quarter, the second fiscal quarter of 2007 at which time we would expect to be generating cash flow from operations.
	At June 30, 2006 we had 24,986,205 shares outstanding, 5,641,000 stock options and warrants outstanding, many of those under water at this point.
	As we’ve stated previously, the company does not have any convertible debt, preferred stock or other equity instruments outstanding other than the stock options and warrants which have been disclosed in past SEC filings.
	With that, I think I’m going to wrap up the financial part of this presentation and open it up for questions.
Operator	Thank you. Ladies and gentlemen, at this time we will begin the question and answer session. If you have a question, please press the star followed by the one on your pushbutton phone. If you would like to decline from the polling process, press the star followed by the two. You will hear a three-toned prompt acknowledging your selection. Please ask one question and one follow up and re-queue for addition questions. If you are using speaker equipment you’ll need to lift the handset before pressing the numbers. One moment for our first question.
	Our first question comes from Kurt Hallead with RBC Capital Markets. Please go ahead.
K. Hallead	Good morning..
Management	Good morning, Kurt.
K. Hallead	Can you give us an update as to what the extent and level of interest is beyond Gasco for use of this system and whether or not you have potentially anything else lined up before the end of the year?
J. Terry	Yes, Kurt, this is Jim. We do. We continue to have conversations with about 4 operators, all much larger than Gasco. We expect that probably to grow by about 2 more as the result of some activities next week. I’ve been to the Middle East with Mr. Galloway, meeting with some of the major service companies over there. As I said, that won’t result in revenue that we can anticipate any time in the near future.

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	I’d say putting the second unit to work pretty much on delivery shouldn’t be an issue. As you know, Gasco’s bringing on a second high quality rig towards the end of this year as well so that probably gives us a 2 system market just with Gasco.
K. Hallead	Assuming this next well goes as planned and you do demonstrate the same sort of success on a continuous basis that you did on that last day of drilling on the prior well, is it quite possible or feasible if you have a backlog of E&P companies that want to use your system to potentially have them give you a firm contract that will help you at least finance some additional systems?
J. Terry	I would certainly expect so.
K. Hallead	Okay. So you think that there’s ... along those lines then you think that is in the realm of possibility. That’s not a crazy assumption to make on a relatively new technology?
J. Terry	No. I mean we had a 3 well agreement with Gasco without ever having pulled the trigger below 2,000 feet. Based upon the conversations we are having and that have been ongoing for some time with other operators, I think that’s very likely as opposed to just possible.
K. Hallead	Jim, I may have missed what you said about ... I know you’re going to at some point replace the frac system so you said you have something in process. When do you think you might have a non-frac pump system in the field?
J. Terry	I think we’ll begin testing it as a backup to the primary frac-driven injector probably on a well before the end of the year. As far as when we determine that that’s a commercial go-forward operation on a primary basis, Kurt, will really depend upon the testing. So there’s 2 phases of testing. There’s the laboratory testing that I said will commence in 2 weeks and then when we get comfortable enough with that, we’ll take it out as a backup on a real well and depending upon how that testing goes, will drive that.
	As I’ve said previously, we’re not going to stifle our growth for lack of having the new injector system; we’ll go with what’s proven albeit not the most elegant solution.
K. Hallead	And then in your press release you said on this Gasco well you might have something to say late August, early September. Can you give us any indications between now and then as to whether or not that timeframe will be firm or whether it might get pushed to the right. Probably a lot of that has to relate to whether or not Gasco’s going to be ready for you at that time. Is that true?

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J. Terry	Yeah, your last statement. The night before last they got stuck just short a TD so they backed off and that operation’s been delayed a little bit. But I don’t anticipate that even that’s going to cost us more than about a week. My expectation that we’ll have results in September, I think that’ll be the case.
K. Hallead	Alright. I’ll open it up for anybody else. Thanks.
J. Terry	Thank you.
Operator	Our next question comes from Pierre Conner with Capital One Southcoast. Please go ahead.
P. Conner	Good morning, everybody. Jim, a follow up on some of the testing of magnetic drum system, or Greg, whoever would be more prepared. Could you detail a little bit more about some of testing that you’ve done I think at Catoosa? Just give us a little more on the details of the testing you’ve done on the system before taking it out to the field.
J. Terry	I think I’ll let Greg address that because he’s there hand-on every day working with that system. Greg.
G. Galloway	We haven’t gone to ... you mentioned Catoosa, those were previous tests. What we’ve done since the first Gasco well is do testing at our facility, test facility, R&D facility here in Houston. We did a number of things primarily focused on the shot recovery system, basically filtering the shot out of the mud stream and recirculating it. We did a complete test of all the components involved in that including the demagnetizer, the magnetic drum and the conveyor systems so we’re fully confident that those will function as designed and as per our expectations.
	We also did some additional tests on the injector system, the frac pump and the 2-stage inductors, basically better defining our operating window for that equipment which we feel like we’ve got a much better handle today than we did previously.
P. Conner	Thanks, Greg. Also related to modifications, Jim mentioned and you characterized them as minor modifications to the bit. If you could maybe just expand upon those modifications and again if there were any testings on that ahead of field implementation.
J. Terry	Yes, Pierre. The modifications we made are basically to replace a 2-piece nozzle configuration with a single piece. That just adds a little bit more durability or ruggedability to the nozzles.
	We also changed very slightly the angle of the center jet which we think will reduce the thickness of the rock ring, the center rock ring for increased of

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	rate penetration. And really the balance of it was inconsequential. We haven’t tested it but these are pretty minor iterations and we’ve got a significant database of test results on prior testing so we’re real comfortable that we understand exactly what we’ve done with the bit.
P. Conner	Okay, thanks. Then the last one, the rig related downtime and maybe this is to remind me, but 90% of your downtime is related to the shot recovery system but of the overall downtime, last time on the test was rig components, testing, etc. Could you expand on that one relative to what you’ll have them do prior to you rigging up?
J. Terry	Again, I’ll let Greg address that.
G. Galloway	Basically the rig related downtime was pressure events. With the rig operating typically at 2,000 psi, when we ask it to operate at 4,000 psi, though the equipment is ready for it, it hadn’t been run at those levels for quite some time.
	The primary downtime was a result of that increase in pressure that we were operating at or asking it to operate at versus what it’s normally operated at. We believe we’ve got those sorted out. There’s evidence for that on the last run that we had and we think going forward there should be no change and we’ll hit the ground running.
P. Conner	Great. Thanks, Greg. Thanks, gentlemen, I’ll turn it back.
J. Terry	Thanks, Pierre.
Operator	Our next question comes from Christopher Greenwell with Tejas Securities. Please go ahead.
C. Greenwell	Good morning.
J. Terry	Good morning, Chris.
C. Greenwell	Would you be so kind as to quantify the savings associated with the frac pump being replaced with the new injector system? I know you had in prior calls, I just wanted to make sure my number was correct.
C. Boswell	As we have developed the new injector system, I think we’re still learning quite a bit about that. The frac pump that we just acquired was $1.2 million. So on a cap ex side I think we’re looking at seeing a way to reduce the cap ex cost by at least $600,000. In terms of the operating costs, the carbide parts and the 2-stage adductor are about $2,000 a day. Fuel on top of that for the frac pump is about $5,000 a day so there’s $7. You add some people, you’re getting pretty close to $9,000 a day in op ex that’s benefits. Virtually all of it goes away.

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C. Greenwell	Great. Thank you very much.
C. Boswell	Yes, sir.
Operator	Management, this concludes our question and answer session. I would like to turn the conference back over to you for any closing comments.
J. Terry	I appreciate everybody’s attendance today and we look forward to being able to disclose the results of what we think will be a very successful test in September. We’ll certainly keep you updated as we make progress on the new components when there’s some tangible evidence to disclose. Again, thank you very much.
Operator	Thank you. Ladies and gentlemen, this concludes the Particle Drilling third quarter earnings conference call. Thank you for participating, you may now disconnect.

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