Evolution Petroleum Corp (EPM) 2008 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you so much for standing by. Welcome to the Evolution Petroleum fourth quarter and year end earnings conference call for the fiscal year ending June 30, 2008.

During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded today on Tuesday, September 23, 2008.

I'll now turn the conference over to Ms. Lisa Elliott of DRG&E. Please go ahead, ma'am.

Good morning. Thank you, everyone, for joining us for Evolution Petroleum's conference call to review 2008 fiscal fourth quarter and year end results. Before I turn the call over to management, I have a few items to go over. If you would like to be on one of the Company's e-mail distribution lists to receive future news releases please call DRG&E's office at 713-529-6600 and someone will be glad to help you.

If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Company's website at www.evolutionpetroleum.com or a recorded replay until September 30, 2008. To use the replay feature, call 303-590-3000 and dial the passcode 11119784. Information recorded on this call speaks only as of today, September 23, 2008 and, therefore, time-sensitive information may no longer be accurate as of the date of any replay.

Today, management's going to discuss certain topics that contain forward-looking information, which is based on management's beliefs, as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected future drilling results, production and expenses.

Although management believes that expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties and assumptions, including, among other things, oil and gas price volatility, uncertainties inherent in oil and gas operations, and estimated reserves, unexpected future capital expenditures, competition, governmental regulation and other factors described in the Company's filings with the Securities and Exchange Commission.

Should one or more of these risks materialize or should underlying assumptions prove incorrect, accurate results may differ materially from those expected. Today's call may also include discussion of probable and possible reserves or terms like volumes, reserve potential, or recoverable reserves.

The SEC generally only allows disclosure of proved reserves and security filings and these estimates of non-proved reserves or resources are by their very nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk. Please also note that the press release dated September 4 put out by the Company provided the Company's year end reserves as of July 1, 2008 and contained reconciliations and definitions of PV-10 and probable and possible reserves.

Now I would like to turn the call over to Mr. Bob Herlin, Evolution's Chief Executive Officer. Bob?

Thanks, Lisa, and good morning to everyone. With me today also is Sterling McDonald, our CFO. Hopefully, you've had a chance to review our news releases issued this morning. Sterling will go through the numbers contained therein a little later on in the call. First, I would like to go through the highlights and review our operational results.

To start with, we're pleased to have reported net income through fiscal fourth quarter ended June 30 of '08 and we believe that we've now turned the corner on being profitable. Of course that's subject to future oil and gas price volatility and the pace that we have in bringing on new wells to replace normal production declines.

In our fourth fiscal quarter, we generated net income of almost $400,000, or about a little over $0.01 per diluted share on revenues of $2.4 million. This is a very substantial improvement over the prior year fourth quarter of about $0.02 per share loss on revenue of about $0.5 million. The improvement in operating results is due directly to our drilling activity in the Giddings Field in central Texas.

Last year in the similar period, our revenue was entirely from production in the Tullos Field in central Louisiana, plus our interest income of about $400,000. Since we sold our interest in that Tullos Field in March of this year, all of our production since has been in the Giddings Field.

Sales volume in the recent quarter were about 18,200 barrels of oil and natural gas liquids and 53 million cubic feet of natural gas, or just a little over 27,000 barrels of oil equivalent. This is about a 230% increase over sales volumes in the fourth quarter of '07 and 180% increase over volumes sold in the third fiscal quarter of '08, or the immediately prior quarter, therefore, showing how much of an increase that we've actually generated.

In June of this year, we completed the first phase of our development drilling program in the Giddings Field and we brought on production the last two wells in our initial six-well program. Five of these wells were reentries into existing well bores where we drilled a new horizontal leg within the Austin Chalk formation, tapping into fractures that haven't previously been developed. One of the wells was a grassroots location where we actually drilled a new vertical hole before we drilled out our horizontal leg.

The six wells total combined for about 22,000 feet of horizontal drilling section, which is a little more than what we originally had contemplated when we started the fiscal year with a 10-well program. That 10-well program was adjusted to six-well program and some of those six wells had multiple laterals. Our total program costs, our drilling costs of $12 million turned out to be a little bit more than we expected. This is due to higher costs of services and materials, unexpected downhaul mechanical problems in the reentries and a little higher -- actually substantially more higher than expected loss of drilling fluid within depleted fractures that we encountered.

However, as a group the wells have performed about as expected. We have taken the information we've gained from that drilling and adjusted our second phase of drilling to incorporate that knowledge. Our goal, obviously, is to better than expected in our next drilling program.

I would like to remind shareholders that, and listeners, that among the reasons that we have targeted the Giddings Field is that our team has extensive experience in this area. I led the drilling of 28 horizontal wells around 1990. Daryl Mazzanti, our VP of Operations and Eddie Schell, our General Manager of Drilling, have spent much, if not most of their career working in that area.

Although the Giddings Field has produced over 1.25 billion barrels of oil equivalent to date, we still believe that it holds substantial amounts of oil and rich gas that can be produced economically. We estimate that our drill and complete costs over the full program going forward is going to be in the neighborhood of $16 to $18 per barrel of oil equivalent. I should point out that Giddings' production is not long-lived production.

It does generate good cash flows, however, and near-term revenues and earnings for us, which is appropriate, while our Delhi CO2 project transitions into project in late 2009 and early 2010. Therefore, the Giddings Field project is a real good balance to our Delhi long-life reserves and [mid-flow] and steadily increasing production profile as the various phases of Delhi are brought online.

Again, by the end of June, we had six of our drilled wells on production, plus a seventh well that we had acquired through leasing that we restored production through a workover. Due to the normal high initial decline rate, the fact that three of our newest wells produced only for a limited portion of that month, including two of our best three producers, June '08 production averaged about 580 barrels of oil equivalent per day gross.

Net, that's about 468 barrels of oil equivalent per day. We own 100% working interest in all of these wells.

Going forward, it's our intent to update the public and shareholders pretty much on a quarterly basis. We don't do it on a well-by-well basis. When evaluating our Giddings drilling operations, we really ask that people focus on it as a program and not on an individual well-by-well result. We have seen in our first six wells and expect to continue seeing in the second phase of drilling a range of outcomes, anywhere from poor to excellent results.

And as I noted earlier, we learn from each of these wells and we apply that knowledge to improve the probability of obtaining good wells and reduce the probability of getting poor wells. Each one is going to have its own production characteristics, but in aggregate we are pleased with the results so far and look forward to our next drilling program.

Within the Giddings Field, we have a total of 27 proved locations to drill in addition to the seven producing wells we have there for a total of 34 wells. This compares to the 12 locations that we had at the beginning of fiscal '08, or an increase of 22 locations total. Our goal in '09 is to continue adding proved undeveloped locations while executing on our 10-well reentry program.

Now, under SEC guidelines, our independent reservoir engineer has assigned 4 million barrels of oil equivalent proved reserves to our interest in the Giddings Field. Based on the substantial available production and offset wells, of which there are over 11,000 wells in the Field, our independent engineer has further assigned of 3.1 million barrels of oil equivalent of probable reserves to our interest, all as of July 1 of '08 for a total of over 7 million barrels of oil equivalent net to our interest.

Now, the proved reserves of 4 million include 2.25 million barrels of crude oil condensate natural gas liquids and 10.5 Bcf of natural gas. Separate from all these reserves, we've internally determined that our interest in the Delhi Field CO2 project in Louisiana total approximately 13.4 million barrels of net probable reserves. These are not eligible for classification as proved reserves until the CO2's actually being injected in the field and we've obtained a production response in the field.

We think that this is going to occur sometime in late 2009, possibly early 2010. Net proved reserves during the fiscal year increased altogether about 133% over the prior fiscal year total of 1.7 million barrels. This 2.3-million-barrel increase is over and above replacement of reserves sold in the Tullos Field, totaling almost 700,000 barrels. This sale was in March of '08. It's also over and above our production during the year of some 50,000 barrels equivalent.

As a result, our net proved reserve additions totaled about 3 million total barrels of oil and gas equivalent. Now, in our news release of September 4, we reported that our PV-10 for our SEC proved reserves increased from 33 million, or about $1 per fully diluted share July 1 of '07 to $160 million, or $4.83 per fully diluted share as of July 1 of '08. I really need to point out, though, that our NYMEX prices that we had to utilize on July 1 of '08 was $140 per barrel of oil, $84 per barrel of liquid and just over $13 per million BTUs for gas. This is compared to July 1, '07 prices of a little over $70 per barrel of oil and $6.80 per million BTUs for gas.

Our PV-10 calculations are net of capital expenditures of $62.5 million as of July 1 of '08 and $18.5 million of July 1 '07. Now, obviously commodity prices have come down quite a bit since July 1 of '08. We had our third party engineers rerun the numbers using a lower price of $110 oil, $8 gas and $67 gas liquid price.

And on that basis, the proved reserves PV-10 on the SEC basis came in about 38% lower at $98.6 million, or about $3 per diluted share. Now, before I discuss our CapEx plan for fiscal '09, I'm going to turn this over to Sterling and he'll review our financial results.

Thanks, Bob. I would like to also thank all of you for joining us today and please note the financial information we discuss today will be filed in our 10-K sometime later today.

One amplification on a point that Bob covered relative to our proved reserves increasing 133%, the 2.3 million barrel increases over the replacement of 0.68 million, I think he said 700,000 barrels of proved reserves, those all include not only the sales of Tullos, which was 400 and some thousand barrels, but also net of production and adjustments, all totaling 680,000 barrels.

Focusing on our financial results for our fiscal year ended June 30, 2008, oil and gas revenues were up 128% to $4.3 million compared to $1.9 million in fiscal year 2007. Focusing on fiscal Q4 '08, oil and gas revenues were up more than 360% and $2.4 million from $500,000 in fiscal Q4 '07. In fact, Q4 '08 revenues represented more than 50% of our total fiscal year revenues, despite no contribution from our March 3, 2008 divested production phase at Tullos prior to the fourth quarter.

Fourth quarter realized prices for oil were $130 and change per barrel, up about 111% from a year ago, while natural gas was $10.24 per Mcf and natural gas liquids were almost $65 a barrel. For fiscal year 2008, realized prices were $99.03 per barrel, up 53% from last year, while natural gas was $9.67 per Mcf and natural gas liquids were $63.02 per barrel. We had no natural gas or natural gas liquid sales in the fourth quarter or the full year of fiscal 2007.

On a BOE basis, realized prices increased 40% from the prior year's comparable quarter and 27% year-over-year. Our total sales volumes in the fourth quarter including natural gas and natural gas liquids increased 230% to a little over 27,000 barrels of oil equivalent compared to about 8,200 barrels of oil equivalent in the fourth quarter of 2007. This was accomplished despite the Tullos sale in the spring.

Our total sales volumes for fiscal year '08 increased 79% to 51,614 barrels of oil equivalent compared to 28,800 BOE in fiscal 2007. In terms of costs, lease operating expenses for Q4 '08 declined 9% to $284,000, while for fiscal year '08 they were down 7% to $1.3 million.

The overall decrease in lease operating expenses in 2008 is primarily due to marginally lower monthly field expenses incurred over four months at our Giddings Field as compared to the somewhat higher monthly field expenses incurred at Tullos over eight months. However, on a BOE basis lease operating expenses decreased 47% during fiscal year '08 and decreased 70% in Q4 '08 due primarily to much higher production volumes at Giddings as compared to Tullos.

DD&A expense increased $612,000 to $903,000 for fiscal year '08 from $291,000 for fiscal year '07. The increase is primarily due to much higher daily production volumes at Giddings over Tullos and a higher depletion rate, $16 versus $10 per BOE. The increase in depletion is due to the higher development cost of PUDs in the Giddings Field that we added and replacement of our lower cost proved developed producing reserves from our properties in the Tullos Field area.

G&A expenses increased 22% to approximately $5.5 million for fiscal year ''08 to $4.5 million in fiscal '07. Higher overall compensation expenses and new hires accounted for the majority of the increase. Please note that non-cash stock compensation expense was $1.8 million for fiscal year '08 compared to about $1.6 million for fiscal year 2007, thus our cash G&A expense was about $3.7 million for 2008.

The additional head count that is associated with the buildup of our infrastructure to execute our drilling program in the Giddings Field -- what happened to my page? Got it. G&A for fiscal year '08 declined to $1.4 million from approximately $1.5 million in fiscal quarter '07 -- I'm sorry. Let me restate that. G&A for Q4 '08 declined to $1.4 million from approximately $1.5 million in Q4 '07.

The expense of our higher head count in the fourth quarter was more than offset by capitalization of personnel costs associated with our Giddings development activities. Interest income for fiscal '08 decreased $1.1 million to $850,000 compared to $1.9 million of interest income for fiscal '07. The decrease in interest income is due to lower available cash balances averaging approximately $20 million during fiscal year '08 compared to cash balances averaging approximately $36 million during fiscal year '07. This was combined with a lower interest rate environment, fiscal year '08 over '07.

Lower cash balance is mostly due to cash used to pay income taxes originating from our Delhi Farmout to Denbury and investments of cash into our Giddings and Oklahoma gas shale projects. During 2008, we maintained our cash liquidity by continuing to avoid structurally enhanced investment vehicles, auction rate securities and other questionable credit instruments, instead utilizing lower yielding U.S. government agency money market funds.

With credit market issues accelerating this summer, we moved again our investments this time into U.S. Treasury money market funds to avoid potential agency exposure. As an added level of liquidity, we point out that we continue to remain debt free.

EBITDA was approximately $1.2 million for the fourth quarter ended June 30, 2008. This consisted of income from operations of $59,000, plus the following: DD&A, $530,000, non-cash stock comp expense, $480,000, and net interest income of $81,000. This compares to a negative EBITDA in the fiscal fourth quarter of fiscal 2007.

Summing it all up, we reported our first positive net income in the fourth quarter without the aid of a capital gain of $377,000, or about $0.01 per diluted share compared to a loss of $474,000, or a loss of $0.02 per diluted share in last year's fourth quarter. For fiscal year '08, we reported a net loss of almost $1.6 million or $0.06 per fully diluted share compared to a net loss of $1.8 million, or $0.07 loss per diluted share in fiscal '07.

Our 2009 capital expenditures program is expected to be funded primarily from working capital and funds from operations with a part of the balance from other sources. We recognize that the world and U.S. economies are experiencing unprecedented capital market stress and volatility, which makes us even more determined to live within our means.

Consequently, we may reduce our capital expenditures from our $19 million budget based on a number of factors, including changes in the commodity prices that we expect to receive, building and production performance results from new and existing wells, unexpected changes in our working capital, insufficient joint venture capital, or such other factors as we deem appropriate.

We do believe, however, that any retrenchment would be brief, only serving as a bridge to reach our expected annuity from Delhi production, which appears to be around the corner for the benefit of our shareholders. This concludes my remarks and now I'll hand the call back to Bob.

Thanks, Sterling. A couple of weeks ago we announced that our capital budget for fiscal '09 expected to be $19 million subject, of course, to commodity prices and drilling results. We expect to allocate about $3 million of that to leasing and $16 million to drilling. Now that drilling activity is going to be composed of 10 horizontal reentries within the Giddings Field and initial drilling in the Woodford Shale in Oklahoma, plus up to three wells in a new development project in Texas. Now that program of $19 million compares to $21.5 million incurred in the prior year of fiscal '08, of which $13 million was used in drilling and the balance in leasing in Texas and Oklahoma.

Our first well to be drilled is expected to spud within the next month and the program will consist of drilling three to four wells and then a pause to review the results, incorporate the information gain, and then commence the next set of wells. Again, initial rates will tend to decline rapidly. Each well is independent of the others, and well results will vary around a program mean.

Austin Chalk and Georgetown reservoirs typically produce half of their reserves within the first two years or so and then produce at a much lower rate for another 10-plus years. We expect also to initiate drilling in the Woodford shale in Oklahoma later this fiscal year. Now, originally we intended to start with a testing program to determine best completion practices and likely production rates.

We have been fortunate in that other operators in the area are drilling and completing wells into the Woodford Shale around our acreage, some 50-plus wells to date. Now, the publicized results of those will provide us with a lot of the information that we are looking for from those tests. Therefore, we can pretty much skip the testing phase and go directly towards development drilling.

At this point, we haven't quantified the projected gas reserves potential on our acreage, but we do believe that our net acreage position will eventually yield us up to 200 net drilling locations. Now, we're still leasing in Oklahoma, but we currently have over 17,600 net acres leased to date. Now, also in fiscal 2009, we anticipate drilling three wells in a new development project and it's located in Texas.

We really aren't going into any details on that project since we're in the early leasing phase and we prefer not to disclose anything about that in a competitive leasing environment. It is an oil play and we will be applying completion technology that we developed over in the Tullos Field, Louisiana.

Our CO2 project at Delhi continues to move forward. After a little bit of a regulatory delay, Denbury has reported that they have secured the permits to complete the second half of the CO2 pipeline to Delhi. They have acquired the necessary pipe and the construction is underway. They are also working in the field, adding infrastructure and preparing wells to take on the CO2 and go out for production.

They announced their plan to begin injection in the second quarter of calendar '09 and anticipate that first production will be about six months after first injection occurs. I would like to point out that Denbury has invested to date over $123 million in the project through calendar '07. They have another $80 million budgeted for '08, obviously a large portion of that's already been spent. Denbury has further quantified that its Delhi interests represent 33 million barrels of net probable oil reserves as engineered by their outside engineer.

Now, with less than three quarters to go before injection of CO2 begins and with future capital outlays less than what they have spent to date, we think that a major delay or change of heart at this stage is highly unlikely. So this is a project that is going forward.

To date, our Company has demonstrated that we have an ability to identify development projects and to implement those projects to grow share value. We think that our recent financial results demonstrate that we are converting that value into revenues, earnings and cash flows.

We continue to develop new projects while maturing our existing portfolio and with a strong balance sheet and these quality assets and experienced staff, we believe that we can continue this success. Now, with that, I would be happy to take your questions.

Thank you. Ladies and gentlemen, at this time we will begin our question-and-answer session. (OPERATOR INSTRUCTIONS) Our first question's from the line of Jason Wangler with Dahlman Rose. Please go ahead.

Hi, guys. This is Neal. Two things real quick, one, you did touch a bit on service costs. I'm wondering with what you're seeing on costs now, obviously, what you have going on with Giddings and two of the other newer plays, will you kind of keep your, I guess, style or whatever you want to call it, the same as far as going forward as far as contracting rigs or, are rigs tight enough now where you, especially in Giddings, I guess, you have to lock that rig in for a while? I'm just wondering what you're seeing more on the costs there?

Neal, the service costs are definitely elastic to what's going on in oil and gas commodity price, but there is a time lag involved. Obviously, we like to see service costs come down. We haven't seen that yet. I anticipate that they will as long as gas prices stay down in the $8, $7.50 range.

The type of rig that we use for our reentry program in the Giddings Field is not the same rig that is in high demand, for example, up in the Haynesville play. And so we haven't seen a lot of rig-on-rig competition. We are confident and actually have our first rig lined up and ready to go.

We don't anticipate entering into a long-term contract. We don't think that that -- at this point in time that it's a benefit to us or necessary and we would like to retain the flexibility to try and reap maybe some future productions and service prices.

Okay, and then one other, [Jim], I know you all are always looking at a lot of different things out there with your staff. I mean has the market -- I mean obviously we're in a volatile commodity market.

Just kind of curious as far as plays you're looking at, costs out there as you're looking, are they still the same as what they were three months ago? Are they still moving up? Are we seeing a lot of difference if you're looking at, I don't know, a Giddings area versus your Oklahoma area, are you seeing a lot of variance in sort of costs of different plays? Just kind of curious to, I guess, the overall M&A market as you're seeing it out there?

Well, we're not really in the M&A market. Our mode of operation is to develop projects where we can acquire acreage at a low price. We don't get into competing with other people in the Haynesville or Barnett or whatever, paying $15,000, $20,000 an acre. We would like to get in much, much cheaper costs. I did allude to our latest project. It is an oil-based project. It represents an area that, where we can acquire leases at a very low price and the price of oil that we need to be successful is far, far lower than current prices.

And so whether or not oil is $100, 110 or $120 or $90 really is not -- it does not impact the economics, so we're somewhat indifferent in terms of going forward on new projects. Obviously, it does have impact in terms of what revenues are generating, cash flows going forward that we can use to fund projects. But I think like a lot of people, we have projected lower oil and gas prices in terms of calculating or estimating what kind of cash flows we have to work with.

Okay, one last one maybe, I'm not sure whether this is Bob or you or Sterling, as far as now when you're looking at sort of going forward on CapEx and sort of where your stock is, I mean do you consider, especially given to me how cheap I think your stock is, with some of your cash flow, would you consider buying back shares or is it more you still see a better return on some of your plays? Just wondering, if Sterling's allocating some of the cash, what the thought process is there?

We're continuing to try to convert our kind of static reserve values into more dynamic production and we've looked at that for, I mean, gosh, our stock was -- when we closed with Denbury, our stock got back down into the dollar range and we looked at it.

But we just don't have enough cash to sock it all up and we're going to continue our operating plan and continue to -- bear in mind that we're just now turning the corner on earnings and cash flow and we need to make sure that we see ourselves to the day of the Denbury annuity beginning and I think that's probably the most important thing for this year.

Another way of looking at it is, obviously, we agree that our stock price is extremely discounted in the market and let's say that, it should be four times higher. So you buy share of stock for a dollar and it's worth $4 in our mind. One other way of looking at it from our perspective is, okay, in the Giddings Field, we invested $4-plus million in leasing plus a year of our -- year and a half of our time and have generated PV-10 of proved reserves of $100 million. So that's a, what, a 15, 20 to 1 return on investment. So as long as I can take my cash and invest it and get those kind of returns, I'm going to do that as opposed to buying stock in the market.

Okay.

Neal, also, your follow-up on your service costs, Bob, isn't it true that we're bringing back the same rig--

Right, we're using the same drilling rig that we used on three of our first six wells and this is a rig that is especially usable for reentries and has worked for 20 years in the Giddings Field. We traded this rig back and forthwith a couple people we know and hopefully we can keep it friendly out there and continue to have it when we need it and they have it when they need it.

I checked on rig rates. As it relates to this particular rig, our rate is flat. This coming development program that we're beginning, rates are flat with what we experienced six months ago when we used this rig for our first phase. As we're -- we just checked with Eddie, our General Manager of Drilling. Apparently the deeper stuff, the rates have continued to go up, but that's not where we're focused right this moment.

Got it. Perfect. Thanks, guys. Look forward to all the activity and the Denbury annuity starting.

Great, thank you.

Thank you. Our next question is from the line of Richard Rossi with Collins Stewart. Go ahead.

Good morning, everybody. Just a couple of things of clarification. I'm not sure that I heard you right. Did you say that the 13 million barrel of oil probable reserves out of Delhi goes into proved late '09 or '10, or are you just -- will begin to just see some proved out of that 13 million barrels?

Thanks, Rich. The reserves we have at Delhi, the 13.4 million barrels, are currently labeled through internal valuation to be probable reserves and it just so happens that when we do a back calculation that ties directly into the numbers that Denbury has published as being their net reserves as evaluated by their outside engineer.

Under SEC rules and guidelines as currently promulgated, we cannot begin -- those reserves are not eligible for categorization as proved reserves until we have CO2 being injected, put into production response, which we believe will occur, both of those occur by the end of calendar '09. How much of that is converted into proved and how much is retained as probable is going to be subject to what the outside reservoir engineer determines.

We would expect and hope that the majority of those reserves will be classified as proved, but that's going to be up to the engineer.

Okay. That's what I thought. I just wanted to make sure -- I thought you were saying something a little bit different. But that was my mistake.

Now, Rich, to follow up on that, also you may be aware that the SEC has proposed now rules around this.

Right.

And we've actually -- we've made our comments as it pertains to reserve accounting and one of the areas we delved into pretty deeply was the concept of analogous fields that have had recoveries demonstrated, et cetera, could be categorized as proved reserves.

If that occurs, though, I'm not sure that those rules are going to beat us to the finish line here in getting our field up and running. So it may not provide us additional latitude in making our probables proved. But going forward, it might.

Okay. And just one other thing, I mean Giddings is still relatively early, but what's your hedging philosophy going forward?

Well, typically you hedge to protect financial obligations of the Company. Since we don't have debt, we don't have a fixed obligation that we really have got to hit other than our overhead and we're covering overhead right now fairly easily. What the cash flow for operations and capital programs. I mean philosophically, if I have -- or when I have a well established production that I can project forward confidently in a substantial amount, combined with oil prices or gas prices that I believe are much higher than are reasonable expectations, then I might consider hedging. Other than that I would not be inclined to hedge.

Okay. Just wanted to cover that. Very good.

The other issue there, Rich, that we talk about here internally a lot and have for the last two years has been counter party risk. And if you look at when hedging's been used for financial transactions, it's basically been in an up commodity market.

Right.

Where the bigger issues are obtained at the well head from the producer out of his string. The concern we have is the market goes the other direction and we have no collateral against counterpart and as matter of fact, you may have seen Lyn's announcement this week that they have got a $60 million hickey they will be looking at Lehman to reimburse them for because they moved out of those contracts and replaced them with another counter party. Well, that's an executory contract -- they will probably get nothing for that claim, so we're already starting to see some of it.

All right.

You know, that makes you kind of -- heads you lose, tails you lose.

It's getting to be a tougher and tougher world out there. All right. Thanks very much.

Thank you, Rich.

Thank you. Our next question is from the line of Joel Musante with C.K. Cooper and Company. Please go ahead, sir.

Hi, Bob. Hi, Sterling.

Hi, Joel.

Yes, I had a question about Giddings. I remember back in, I believe it was June, you guys indicated you would be evaluating the Giddings program and before you lay out your 2009 plan, and I was just wondering what you found in that evaluation and how it influenced your 2009 plan?

Sure. What we learned from our drilling program this spring is that certain areas of the Giddings field are more amenable to this reentry program than others. We found one area had a little more depletion and problems in terms of absorbing drilling fluid that you then had to produce [back] before you could get meaningful oil and gas production. So that area of the field we have deemphasized going forward in terms of our locations.

The locations that we've retained in the program and are focusing on adding new locations are more in the areas that we've had much better results in. We've also determined that we got better results whenever we had a little more spacing from offset wells and so we have incorporated that as well. We are focusing on our -- on proved locations that have greater spacing between our proposed lateral and the offset well.

I think -- and then the other thing that we've picked up on is in terms of how we actually drill the wells, we've seen that in industry right -- the service industry right now, it's best to make sure that you don't run into complications. The service industry has been stressed and -- in terms of rapid growth, so getting quality equipment and tools combined with quality people at the same point is difficult and if you have any kind of a problem downhole combined with the service issues, that can quickly turn into an expensive problem.

And so we're going to try and keep our program as simple as possible to avoid those kind of issues and keep our costs under control.

Is that why you're doing reentries as opposed to grassroots wells, mostly in 2009?

No, we have focused on the reentry program when we are using 100% of our own money because of the cost per well. We want to keep that at a reasonable level to allow us to drill enough of the wells to make sure the program reaches its targets. The Austin Chalk is what we call a statistical play.

Each location is totally independent of the next one and each one varies around the mean -- when you're drying the horizontal section in a naturally fractured reservoir, you might get two fracture swarms, you might get 10. It just varies depending on where you are in the rock and you can't really predict that too well. What you can do is project that you're in a good area and that you're going to have a reasonable probability of getting a certain amount of recovery.

But it's still going to be varying around the mean, so you need to make sure you drill enough of those wells to get the good wells to offset the poor wells because you never know which is going to come first.

We can drill a lot of $1.5 million wells to get to the average, but we can't drill many $4 million to $5 million wells to get to the average. We don't have enough money yet.

They both generate reserves and the same costs in our program, it's just that there's not a lot of room for error at $4 million to $5 million a well.

Okay. Thanks. Makes a lot of sense. And just to go to the Woodford, you said that some of the other operators were having encouraging results. Is there anything you can add there that might help us quantify or understand the potential of the play better?

Well, what I can do is relay to you the results that we're seeing in the offset wells. And keep in mind that we have two projects. We have what we call our shallow Woodford project, which is a typical depth of roughly 1,500 feet -- and then we have a play that's in the 4,000 to 5,000-foot depth range. We call that our moderate, or medium depth Woodford Shale project.

On the shallow one, we have an offset. Operators have drilled over 50 wells in and around our acreage. Almost all of those have been vertical wells with limited hydraulic fracks on them, and based on those wells, we believe that a horizontally drilled well with frack will likely produce in the general area of anywhere from a couple hundred Mcf a day to maybe as much as a half million cubic feet a day.

And we're looking at substantial reserves somewhere in an appropriate range goes with that. I don't know what that means, that maybe half million -- half a billion cubic feet or maybe a little bit more. The medium depth, we have one real good offset test right off our acreage, a well that was drilled, horizontally drilled and completed and it came on at roughly a million cubic feet a day this spring and based on reports to date is continuing to make that level of production indicating that the Woodford at that depth is very commercial and very prospective.

So we're very excited really about both areas. We're very pleased. We're especially pleased that we didn't have to drill the wells to get those results.

You know, Bob, the other thing that's significant about the shallow and mid-depth Woodfords compared to the deeper ones, again, it puts us in a window of much less drilling costs per well as opposed to what's going on in the traditional corridor of the Southwest, which is much deeper and those wells are as much as, what, $7 million, Bob?

Yes, the traditional Woodford is around 8,000 to 10,000 feet deep and they are massive multistage fracks are getting 9 to 15 stages. They are costing $5 million to $7 million, and they are generating finding and development costs of roughly $2 per Mcf. Our goal is really not much different in terms of costs per Mcf. It's just that we're doing it on a far cheaper cost per well because the cost of wells are far, far less.

I would like to point out that if you go to our website and pull up our most current presentation, and I believe it's Slide 19, it gives you a little more detail about the Woodford Shale projects in terms of our acreage position, location, and offsets that have been drilled in the relative to the main Woodford Shale trend. So the bottom line is that we think it's got a tremendous upside, tremendous potential, but we're not quite yet ready to start putting numbers in terms of what it is other than if Woodford Shale is traditionally developed on 80 acres or less, then on that same number, it could be as many as 200 wells on our acreage. That's a net well basis.

Obviously, our acreage position will grow through forced pooling, which is allowed in Oklahoma and so we'll likely end up with far more acreage and far more gross wells.

I just wanted to point out, this is Lisa, that the actual slide presentation doesn't have that slide. You have to go listen to the webcast for the Wall Street analyst forum, which is the first link under presentations. So you will find it there on Slide 19.

We will go ahead and post the current -- those recent presentations shortly. That would be Slide 19 once it gets posted. I apologize for that.

Okay, guys. I appreciate it. It was helpful.

Thanks, Joel.

Great, thank you. And our next question is from Rick Feldman with Monarch Capital. Please go ahead with your question.

I'm sorry, who is this?

Dick Feldman, Monarch Capital. Hi, Bob.

Hi, Dick, how are you?

I'm good. I have some further questions about the Woodford. You have spoken in the past about a restraining resource for your Company being people and several hundred wells takes a lot of people. I wonder if you could comment on that situation?

Sure. That couple hundred wells is a program that will be done over a many-year period. Right now, we're just slowly edging into it. We're finishing up our leasing, and our capital program, I state that we will start our initial drilling at the end -- towards the end of the fiscal year, which will be sometime in the spring of calendar '09 or later.

And that will be a slow process. We'll drill our first well or two or three. We have -- our leases typically allow us as much as five years on them, so we have plenty of time to conduct this in a very thoughtful manner. What we're doing is really we're continuing to allow offset operators to prove up our acreage and then once we're ready, then we will start our own program.

In terms of the ability staff-wise to handle that, obviously, we are continuing to add people. We just added our third engineer this summer and I expect that we'll add another engineer sometime after the first of the calendar '09 whose sole focus would be in that area. Staff resources continue to be an issue for industry. We've been very careful that when we add people, it's someone who fits well within our team and our framework of what we do.

We want to be very slow to add people in terms of adding to our overhead burden, and we do -- we do look long-term in terms of when we add those people. So we believe that resources are there and we would allow ourselves plenty of time to add them, the right person at the right time.

Earlier in the presentation, or the question and answers today you talked about your success in leasing up acreage in the Giddings and the very high returns that you were able to earn by doing that. Are you finding acquiring Giddings leases more competitive and think that perhaps returns going forward will be a lot less?

At this point in time, we have not seen a significant increase in our leasing costs in the Giddings Field. Now, I do -- I will have to point out that our leasing component for fiscal '09 is down to $3 million as opposed to a much higher number in fiscal '08. So we will be spending more effort on drilling less on leasing.

The leasing that we are doing is starting to move into other projects and we, at this point in time, see no difference in what we're able to do in terms of being able to deploy capital at a fairly low cost per acre and add substantial proved and probable reserves in that process. So at the moment, I would say that I think that we can continue to a large extent what we've been doing in the past.

The -- one last question. The Texas new project, is that one that deals largely with heavier oils?

Yes, that -- it deals with using that technology we developed over in Tullos for producing heavier oil, not heavy, but it's heavier. I mean there's a difference. You know, heavier meaning, 20 gravity-type oil as opposed -- it's not stuff that requires steam to move. This is just something that -- it's oil in a reservoir that is hard to get out of the ground when you have -- especially when you have water in the area.

Okay. Well, thank you, and good luck. Keep up the good work.

Appreciate it.

Thank you, Dick.

Thank you. (OPERATOR INSTRUCTIONS) Our next question is from the line of Phil McPherson with Global Tiger. Please go ahead.

Global Hunter. Hey, guys. Congratulations on a good quarter.

Thanks, Phil.

Most of the questions have been answered. Just one in particular, when you talk about you have 27 booked PUD locations in the Giddings Field, correct?

Yes.

And if I use your PUDs that you've put in your reserve report, it looks like they are about 0.8 (inaudible) apiece, kind of taking that number as-is, right?

Mm-hmm.

And then you talk about 3.1 probable reserves in the Giddings Field, and the question is, are those probables related to upside revisions to those booked PUDs, or are those another 23 locations to potentially drill?

Those -- the probables are a combination of additional locations and reserves assigned to PUD locations. And the reason for that is partly due to the U.S. SEC rules on how proved, undeveloped reserves are assigned and fractured reservoirs that was issued last fall, fall of '07, where the SEC engineers came out and said they are not going to agree with -- the only proved undeveloped location or fractured reservoir they are going to allow are two locations, each directly offsetting a producing well, but within the same fracture trend. And what that does is that substantially cuts the number of proved locations you might otherwise claim.

We don't necessarily agree with that position. In fact, we would argue that a location that is a direct offset without the fracture trend of that given direct offset, but within the fracture trend of other production that may be several locations away may actually be a better location because you have less risk of depletion. However, regardless, you have to do what the SEC says.

As a result, much of -- not much. Some of our locations were scaled back by our outside engineer in terms of the lateral link was reduced because it may have extend the out of the fracture trend or whatever. And those reductions were moved from proved to a probable category.

In addition, we had I think one, one or more of our locations was moved entirely from a proved to a probable location for that very reason. That would be the explanation for the probable reserves.

Okay, great. And Sterling, what are you using for fiscal year '09 G&A costs?

G&A?

Yes.

I don't expect G&A to vary that much in the coming years. Bob said we may put on another engineer. We -- our capitalization program probably will be similar in that we're going to continue to drill and as we drill, we have direct personnel costs, not Bob or me, or VP of Ops, but more like our General Manager of Drilling and some field personnel that are properly allocatable to capital. But--

Flat basically then from this year?

Pardon me?

Just keep it flat then for modeling purposes?

Yes, I think as an inflation factor. I might put--

10% or something--

7% or something, which probably sounds kind of high, but I think inflation is high.

Okay.

I might do that, but -- that would be across all services. That will be -- bear in mind that we also have a probably disproportionate degree of legal expense relative to SEC matters. Yes, we're a small Company, but we have to deal with everything that a large company has to deal with.

Sure.

In terms of that, and our audit fees are going up. Everything's kind of going up. I don't see big infrastructure additions, but I do see some inflation in our numbers.

That was by far the single largest component of our G&A is our staff and because we outsource most of our operations that we can, our staff is disproportionately higher end salary because the people we have are the ones where the value is created are on the control side and industry is highly competitive right now for people. So as a result, our staff costs are going up higher than maybe other industries would be.

I know you know this, Phil, but a high proportion of our G&A cost is in stock compensation expense and that's non-cash. You got to strip that out. Basically, right now we're looking at about $300,000 a month in cash costs.

Okay, great. And, Bob, I know it's hard to model and you don't give guidance really on production, but from the sounds of your drilling plans, it looks like your fiscal first quarter '09 should be up pretty well from this quarter and then we'll probably have a slight drop in fiscal quarter Q2, and then we'll start resuming that upward curve. Is that a fair statement?

Fair. Well, as you pointed out I don't like to give guidance. I'm not going to argue with you on your numbers.

Great. I appreciate it, guys. Have a good day.

Okay, thank you.

Thank you. (OPERATOR INSTRUCTIONS) Our next question is from the line of Kevin [Arare] with [Kyser Property]. Please go ahead.

Good morning, gentlemen.

Good morning, Kevin.

My question relates to the Delhi project. As far as the estimated recovery of that, are we going know pretty soon about the percentage, whether it's going to be on the low side or the high side, or is this just something that once we take over 11%, we'll just keep on going up to the 20%, if that happens?

That's an excellent question. CO2 floods have been around for decades now and engineers who model them have gotten a pretty good handle on how they work, what the important variables are. In this particular case, Denbury has done over half dozen CO2 floods in that general area, including some in the exact same reservoir rock, but just across the border.

We've got some really good analogs to compare against. You know, typically a CO2 flood recovers between 10% and 20%. Denbury has averaged I believe 17% incremental recovery, if not higher. We've tried to be conservative in our expectations, and I think Denbury has also been very conservative in terms of their projections of recovery going forward. In terms of how you predict what recovery's going to be, that will just take time.

I don't think you can just come out and say, okay, now we have production. It's going to be this percent or that percent. The ultimate recovery is just going to take some time. What the reservoir engineers will do is they will say, well, once we've got -- we've shown that there is recovery, then we'll apply the, what we consider to be the low end of recovery and that will be our proved reserves and then you have to earn into the balance and so the balance will start off as probable, maybe a piece will be possible. Then over time you'll earn in at the higher and higher recoveries.

Okay. And the only other question that I had was the payout to Denbury, is that just the $200 million, or is that based on the margin that you're making on the -- barrels that you're pulling out of the ground?

Well, the answer is really both. It's -- the amount that -- to be paid out is a fixed amount. It's $200 million. How that gets paid out is, obviously, depending upon the margins that we net in the field, which is driven by what is the crude price at the field less the direct operating cost in the field, so whatever that gross margin is goes against that $200 million number.

We estimate that that's a gross production of somewhere in the 5 to 7 million barrels of oil out of a total of 50-plus million barrels in the project. So we think payout will occur early in the life of the project and, therefore, we will have our quarter interest in the project throughout most of the life of the project. And, of course, from day one we have our separate 7.4% overriding royalty interest right off the top.

Okay. Thank you, gentlemen.

Kevin, is Kaiser developing CO2 projects?

No. I'm just a small investor in your Company, just been interested in the Delhi project.

Okay, well, great. We appreciate it, and just an FYI, this is Sterling, I'm from Tulsa.

Okay.

Thank you. Management, there are no further questions at this time. Please continue with any closing comments.

Certainly. I would like to thank everybody for participating, listening this morning, and we look forward to talking to you next quarter.

Thank you, ladies and gentlemen. This does conclude our conference for today. If you would like to listen to a replay of today's conference in its entirety, you can do so by dialing 303-590-3000 and put the access code 11119784.

Once again, to listen to a replay, please dial 303-590-3000 and put the access code 11119784. ACT would like to thank you very much for your participation today. You may now disconnect. Have a very pleasant rest of your day.