Evolution Petroleum Corp (EPM) 2009 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Evolution Petroleum's third-quarter earnings conference call. During today's presentation all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, Thursday, May 14 of 2009.

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

Thank you, and good morning, everyone. We appreciate you joining us for Evolution Petroleum's conference call to review the third quarter of fiscal 2009's results, and that is the period ending March 31.

Before I turn the call over to management I have a few items to go over. If you would like to be on the Company's e-mail distribution list to receive future news releases, please call DRG&E's office, number 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, that is www.EvolutionPetroleum.com, or via recorded replay until May 21, 2009. To use the replay feature call 303-590-3030 and dial pass code 4074414 pound.

Information recorded on this call today is valid only as of today, May 14, 2009, and therefore time-sensitive information may no longer be accurate as of the date of any replay.

Today, management is going to discuss certain topics that may contain forward-looking information, which are based on management's beliefs, as well as assumptions made by management 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 in estimating reserves; unexpected future capital expenditures; competition; government regulation; and other factors described in the Company's filings within the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected.

Today's call may also include discussions of probable and possible reserves or use terms like volumes, reserve potential, or recoverable reserves. The SEC generally only allows disclosure of proved reserves in securities 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.

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

Thanks, Lisa, and good morning to everyone. We certainly appreciate your all joining us today. Joining me this morning is our CFO, Sterling McDonald, and he will go over some of the key financial numbers later on.

First I would like to go over some of the operating highlights with you. As you probably read in our press release this morning, our revenues for the third quarter grew by about 56% over the same quarter in 2008, and sequentially by about 13% over our prior quarter of '09. That growth is due to an increase in sales volumes of about 346% over the last year due to drilling in our Giddings Field project.

Unfortunately, that was offset by about a 65% decline in realized product prices on a fully blended basis. We sold about 43,000 barrels of oil equivalent during the third quarter at an average blended price of $27.27 per barrel or BOE. That price sounds low, but it's because we have a high content of gas and natural gas liquids.

Gas volumes made up about 44% of that total volume; gas liquids 35%; and oil about 21%. The actual prices that we realized for each of those components was about $39.50 for the oil; $23.25 for gas liquids; and $4.12 per Mcf. Obviously, that is far from what we received a year ago, which was $93 oil, $56 gas liquids, and a little over $8 for the gas.

Now sequentially or quarter-to-quarter, we increased production about 63%. That is again primarily due to the high initial production rates from two wells that we drilled during the third quarter and put on production in Giddings.

As we mentioned in our last call, the initial production rates substantially exceeded our expectations. As is typical for Giddings wells, these rates rapidly decline; and they now appear to be stabilizing at their expected rate.

Of these two wells, the best was the Hilton-Yegua #1, which had the highest initial production rate of any well in the history of our Company. We drilled a new vertical section from 3,000 foot depth down to 10,500 feet; and then drilled out horizontally in a single lateral of about 3,000 feet. This is all within the Austin Chalk formation. That well was put online in the second half of January.

In late January, we completed the Pearson #1, which is a pure reentry with a horizontal leg of about 3,500 feet in length, a depth of 10,500 feet. This is within the Georgetown formation, which is very similar to the Austin Chalk.

Now today, we have nine wells producing in the Giddings Field. Total gross productions from those wells in March averaged 482 barrels a day of oil equivalent. Now this is despite two of our best wells being down for about a third of the month for mechanical issues, which have since been repaired.

For example, our Fox well which we drilled and put online last summer had a gas lip valve sticking. We had to go in and pull that and repair it. Then on the Pearson well, our gas purchaser's compressor was down and required work on it; we lost about 10, 11 days production there.

We are also installing our proprietary artificial lift technology in a tenth well. We are doing this to test that technology. It will be our very first field test. We also want to be able to demonstrate the capabilities.

We own 100% of the working interest in all of these 10 wells, and we have an average revenue interest of about 80%.

Now as we mentioned before, since our wells in the Giddings Field, the Austin Chalk and the Georgetown, tend to produce a large portion of their reserves fairly quickly, current prices received are an important part of the economics. Therefore we believe it's in our shareholders' best interest to slow the development drilling of these properties until oil and gas prices improve further or service costs decline substantially further.

We're not under any pressure to drill right now due to lease expirations, and we don't have to worry about servicing debt since we don't have any. We will reevaluate this program and this consideration in a few months, when we start looking at our fiscal 2010 budget.

We feel real good about the results we've had so far in the Giddings Field, particularly the more recent wells, and we look forward to drilling there again when prices allow. We do have 25 proved drilling or reentry locations in our books, and our team has substantial experience in drilling these kinds of wells. So we are comfortable with them.

Now in Oklahoma, we expect to drill our first wells in our shallow Woodford Shale project this quarter. We've already started to work on that process. We have about 17,600 net acres there. Our initial program consists of drilling three very low-cost, local wells at a depth of about 1,500 feet.

Now originally, our plan for this year provided for drilling up to five wells. But in reviewing the information and our acreage position and all of the offset drilling going on around us, we now think that three tests are quite sufficient to accomplish what we want to do here, which is to confirm the acreage, confirm and test completion techniques, and obtain reservoir data.

Due to the very shallow depth that we're at, about 1,500 feet here, we expect to be able to use air drilling, which is a much less expensive process of drilling. As a result we think we can drill, complete, and treat these wells at a cost of about $150,000 per well.

Our goal here or our recovery target is in the order of 200 to 300 million cubic feet per well. One of the objectives with this work is to begin to quantify and convert this resource into a higher category of reserves.

Now during the fourth quarter, we also commenced field work in our Neptune project in South Texas. We have about 1,500 net acres in this particular field that was last drilled during the '90s and is now completely dormant. It's a moderately heavy oil field, about 21 gravity oil, with scores of infill drilling locations.

Now, our infill locations that we have identified are based on historical results of similar infill wells drilled during the '90s. We plan to, as well, test completion technology that we developed and tested in another field late in 2007 and that we believe has the potential to enhance recovery of this moderately heavy oil that is associated with water.

We began looking for an opportunity to apply this technology in early '08, identified this current project in South Texas as a good candidate with fairly low entry cost. Now, regardless of the success of the technology historical results in the field indicate that these infill wells should be quite economic at current oil prices on their own.

We delayed work on Neptune earlier this quarter or in the third quarter when oil prices had fallen into the mid-30s. But since we've had some recovery in oil price, we now have reinitiated that fieldwork in advance of drilling. We expect to drill the first three wells some time in calendar '09 if not a little sooner.

These are going to be very low-cost vertical wells, and we think that the completion costs, drilling and completion, will be somewhere in the $200,000 to $300,000 per well. That should include the water disposal costs.

We continue to limit our capital spending and are focusing our effort and funds on activities that are going to add proved and probable reserves at a low cost. We want to maintain our financial strength so that we can avoid having to raise any equity capital in this depressed market or issue debt at very unattractive terms, particularly related to covenants and collateral requirements.

So our balance sheet and working capital continue to be very strong. Our '09 capital budget called for us to spend up to $10 million; and to date we are at about $8.3 million and don't really expect to spend much more of this capital in the fiscal year, perhaps less than $0.5 million.

This is primarily intended for this initial development drilling up in Oklahoma. During this period, we have maintained our working capital as well with no debt.

Now before I turn the call over to Sterling, let me give you a quick update on Delhi and our CO2 project there. Denbury is expected to start their CO2 injections sometime this summer. This is because the pipeline to the field, the Delta line, has been completed and tested and is expected to be commissioned here shortly.

The CO2 processing facility should be completed sometime later this year. It is our expectation based on Denbury's historical efforts that we can expect first production response within six months after first injection, which would put first initial production response sometime in early 2010.

Our initial revenues from this project will come from our 7.4% royalty interest. Since those have no operating expense associated with them or capital, those cash flows will fall directly to our bottom line immediately.

In addition, our 25% working interest will revert to us in a couple years. We -- at current oil prices and expectations, roughly 2014 is our target time for that. Again that is subject to oil price and the pace of the rollout.

I have emphasized during the year at various presentations and conferences that our capital expenditures and our operating decisions are based on building share underlying value, even if it costs us near-term earnings. I think that our results this quarter bear out that philosophy and that we are maintaining that philosophy.

Now I'm going to turn this over to Sterling to review in detail our financial results.

Thanks, Bob, and thanks to all of you for joining us today. Hopefully you've had a chance to see the earnings release we put out this morning. I won't repeat all the data there that you can easily find, but I would like to provide some color around those numbers.

First, I will go over our liquidity and cash flow, since these are topics that are of high importance to many of you right now and to us. In our third fiscal quarter of 2009 our adjusted EBITDA -- and that is a number that we use that is a typical EBITDA formula but is inclusive of net interest income, since we have no interest expense. We include interest income in that measure. It was a small negative at $170,000 for the current fiscal third quarter, and that was flat with about $176,000 negative in the third quarter of '08. So basically on a pretax cash basis, we're virtually at a breakeven.

For the nine months of 2009 our cash flow from operations was $6.3 million, which you will find on our cash flow statement. This included $6.4 million received from oil and natural gas production, which you won't find on that statement, but I'm breaking this down for you so that you can understand how the cash fits together to get to the $6.3 million.

In addition to the $6.4 million received from oil and natural gas from our properties in Giddings, this was offset by $4.3 million of cash payments for operating activities including lease operating expense, production, taxes, salaries, and G&A.

Additional sources of funds included $4.1 million from income tax refunds, primarily from our 2008 tax year net operating loss carryback. Our cash capital investments in oil and gas properties were $9.9 million, about $2 million of which was from last year's capital program that was incurred in 2008 but paid in 2009.

We also used about $0.9 million to purchase our common stock earlier this year.

At March 31, 2009, our working capital was $7.5 million, basically unchanged from the $7.6 million we had last December. We continue to be debt-free. This compares to working capital of $13.6 million at June 30 '08.

The change in working capital was due to $8.3 million of capital expenditures we incurred -- not necessarily paid in cash, but incurred -- which is from our capital program this year. And that $8.3 million went to natural gas leasehold and development costs for the nine months ended March 31.

Of the $8.3 million incurred, $2.2 million was incurred for leasehold acquisitions and $6.1 million was incurred for development activities. Development activities were in the Giddings Field and leasehold acquisition costs were for properties in Giddings, Woodford Shale projects in Oklahoma, and our Neptune project in South Texas.

As Bob mentioned, our capital budget for the balance of fiscal '09 calls for us to spend approximately $400,000 in the fourth quarter, which leaves us well within our reduced 2009 capital budget of under $10 million.

Our current aim is on building intrinsic value for share as Bob said, so we are focused on low-cost drilling that has the potential to move resources into a proved reserve category. In doing so, we are temporarily suspending drilling activity in the Giddings Field and proceeding with a limited program in our Oklahoma Woodford Shale project and our South Texas project, which is the moderately heavy Neptune oil project, to hopefully prove up additional reserves.

On the expense side, our lease operating expenses declined 79% from our prior year, which stood at $32.72 per BOE. The current period is $6.88 per BOE. This was due to moving our operations from our Tullos Field to our Giddings Field, where operating costs are much less. Sequentially, LOE per BOE was down 45% from $12.54 to $6.88 per BOE on a 65% increase in sales volumes.

Another big impact of the sale of our Tullos asset in March of 2008 was the change in DD&A rate. For the current third quarter, DD&A increased by $620,000 to $760,000, compared to $139,000 for the third quarter of '08. This increase is primarily due to a somewhat higher depletion rate, $17.57 currently at Giddings versus the $13.55 in our previous -- last year's quarter per BOE. But also that rate was applied to a much higher 346% increase in sales volumes.

The increase in the depletion rate is due to the higher development costs of PUDs in the Giddings Field as compared to Tullos. But when combined with lease operating expense, our field level breakeven has declined from $57.92 per BOE we experienced at Tullos during the last full quarter of our ownership to $24.45 per BOE most recently experienced at Giddings. Clearly, our redeployment from Tullos to Giddings is proving itself worthy.

On G&A expenses, G&A increased 26% to $1.6 million for the third quarter of '09. This is primarily due to the completion of the Giddings drilling program in early February '09. Wherein a portion of our staff salaries directly associated with drilling operations were being capitalized, and now they are being expensed to G&A once again.

Also included in G&A is non-cash stock comp expense of about $537,000 or 34% of total G&A for the current period, and $494,000 or 39% of total G&A for the three months ended March 31, 2008.

As we look forward to Q4 '09, we expect to see declining production from our Giddings Field. But by limiting our capital expenditures to preserve our strong working capital base, we believe our working capital is sufficient to carry us through 2009 and 2010 without the need for financing.

Regarding the potential for an impairment charge on our reserves, I mentioned on our last conference call that we had virtually no cushion left for a ceiling test writedown in the third quarter, this third quarter, based on a 12/31/08 price deck.

Since 12/31, natural gas prices have fallen while oil prices rallied. While the disparity in price movements were almost offsetting, we envisioned a small $180,000 writedown based on a March 31 price deck of $3.37 per MMBtu for Houston Ship Channel natural gas and $49.66 prices for NYMEX oil, all of which were adjusted for market differentials.

However, due to the significant rally in both crude oil and natural gas prices subject to March 31, 2009, our cushions increased over $3 million based on May 6, 2009, closing prices, leading us to elect no impairment in accordance with current SEC guidelines.

Looking forward, price declines will still subject us to the possibility of ceiling test impairments, but probably not to the same extent as some of our industry competitors. We have two potential mitigating factors in our favor.

First, most of our current reserve base is proved but undeveloped. As product prices decline, development costs used to calculate PV10s may also decline. This tends to cushion possible impairments as compared to companies with recently high capital costs expended on a large part of their proved reserve base that are already developed, compared to the current low prices suppressing their future PV10s.

In our case, any dollar reductions in capital costs to develop our proved reserve base would be a dollar-for-dollar reduction in the amount of writeoff that we might have due to declining product prices.

Secondly, as proved reserves may be recognized at our Delhi Field, hopefully in the near future, the minimal $1.6 million in booked cost would be minuscule to the royalty and carried interest values we may add from relatively free reserves we look to receive and put into our amortization base at Delhi.

Before that time, however, a March 31 price deck remains the tipping point -- ex, of course, any offsetting declines in future development costs. That completes my comments and I will turn the call back to Bob.

Thanks, Sterling. Before we go on to the Q&A, let me say that we are very excited about the substantial potential for developing low-cost reserves in the Woodford Shale project. We think that we'll be able to add substantial value to our shareholders at a fairly low cost.

Our Neptune project has the potential of being repeatable in similar fields and therefore a potentially significant value as well to shareholders. And our artificial lift technology, if successful, has the potential for being significant.

Of course, we're also pleased that Denbury will soon begin CO2 injection at Delhi and that we can anticipate net oil production there in a relatively soon time frame.

So we think that our activity for the fourth quarter is going to continue to set us up for some great opportunities of growth and value and future revenues in fiscal 2010. With all that, I would like to thank you for joining us this morning and would like to open it up to questions that you might have.

(Operator Instructions) Phil McPherson, Global Hunter Securities.

Nice job on the quarter. Just a couple bigger-picture questions and you kind of started to answer it. On this Neptune project, is like $50 oil your breaking point to do stuff out there? I mean if oil was to go back down. Or what kind of number are you comfortable with, working out there?

Well, I am not going to tell you that there is a bright line that we say, oh, above this price we do it, and below it we don't. I mean even at $35 oil, $38 oil, it was a profitable venture. We could generate net present value.

It's just that we didn't want to, because the dollar return just wasn't attractive enough on a payout basis and so forth. Keep in mind that what we are trying to accomplish with all this is to maintain our financial strength going forward over the next couple years. We really want to stay out of the capital markets as much as possible. So we want to get to the best bang for every buck that we have on our balance sheet.

So I can't tell you right now if it drops to 50, would we stop? No, I won't. We won't do that. I think we are comfortable that oil prices are going to stay high enough to make that attractive going forward for us, that it will generate fairly rapid cash flows to make it an attractive project.

Obviously, if the oil price were to collapse back into the $30s, that would certainly diminish any enthusiasm that we have to spend a lot of money down there.

Great. Kind of same line of questioning for gas prices on the Giddings and the Woodford, if you would. I mean --

Sure. Gas prices, there's really two aspects there. One is, what is the gas price in the major market, Henry Hub? The second is, what is the gas price at the wellhead? So you've got a differential issue.

Obviously, it's very encouraging that prices have improved. But when you're looking at a long-term project, what gas does today or tomorrow or next week isn't of great relevance. It's what you think the gas price is going to be later this year, next year, and the following year.

At the moment, our plan is still one of proving up as much as we can. We want to take resources and move them into possible; we want to take possible and move them up to probable; we want to take probable and move them up to proved. We can do that with fairly small amount of drilling and a small amount of capital expenditures because of the very cheap cost per well.

We can hold acreage, 640 acres with a single well. So we can do a lot without spending or committing a lot of money and then position ourselves for when prices do improve and appear to be improved from the long term. We can then rev up that development program.

So the bottom line is that in Oklahoma our goal is still a limited conceptual proving out process.

Would it be fair to say, Bob, that price is only relevant in the short term to Giddings, but short-term prices are not particularly relevant to what we are going to do right now in the Woodford?

In other words, it's a fair statement?

Yes, okay.

To put a number out there, I mean, I don't want to corner you. But do you think you need to see a $5 wellhead to really want to drill at the Giddings? Is that kind of the number that you model out?

I know you're not leveraged. But would you ever consider -- if prices did pop up off of a -- the gas prices are all over. But would you put a hedge on so that you could drill and realize some of that value, bring that cash flow back in?

Well, first, one thing you said -- well, can you put a hedge on? It's generally really not a good idea to put a hedge on until you have production to support that hedge. Otherwise, you are speculating; and that is not our business. We will only hedge to the extent that we have settled forecastable production to match it with.

Whether gas pops up or whatever, again what's important is not what it does today or tomorrow but what it is looking like it's going to be over the next couple years.

Certainly, if we see prices improve from where they are today, we would be much more enthusiastic about expanding our development process. To a large extent, what I would like to do is use our funds to prove up that project as much as possible, which would then drive down the cost of any external capital that might be brought in to complete the development.

Keep in mind that we also have a very large source of cash flow coming in over the next year or two or three from Delhi. And if we spend the next six months, nine months proving up reserves, then we're in a great position to use our own cash flow to continue that development.

So it gives us a lot of leverage. The easiest way to get cheap capital is if you don't need it. So we would -- we really like being in that position.

Great. I just have one more and then I'll jump off. In relation to Delhi, if my memory serves correct, this field did experience a little bit of a waterflood by the previous operator in the '80s until prices declined. Do you know how that compares to other Denbury fields in response to the first recovery -- or not recovery, first response from the CO2? Is that going to help it maybe pressure up faster? Or is that not -- am I thinking the wrong way?

Well, this field has never been officially waterflooded. What it had was a pressure maintenance project that began back in the 1950s. There is a very significant difference between those two.

A traditional or conventional waterflood has a very high sweep efficiency. You have typically one injection well for every producer. You have what we call inverted four-spot or nine-spot -- inverted five-spot or nine-spot pattern, where every producer is surrounded by at least four injectors on 30- to 40-acre spacing. So you have real good contact between the water and all of the oil reservoir.

That is not what happened in Delhi. In Delhi, the operator during that -- the 1950s through the early '90s was only interested in maintaining reservoir pressure. So they injected water along the downdip side of the reservoir in a fairly haphazard manner. Consequently what you had was water moving through permeability channels from the injection point to the nearest -- we will call -- pressure sink or nearest producer. And therefore, you didn't get good sweep. You didn't get a good thorough contact of water throughout the oil reservoir.

So, we believe that there is still what you would call secondary reserves in the field. The benefit is that means that there is more oil to be recovered through the CO2 injection process.

And the second part of your question was in terms of response and how much pressure do we have to build up. The field, because this is a pressure maintenance project, the field and the reservoirs here have been maintained at fairly high pressure. Actually very close to original bottom-hole pressure. That is why we are expecting a fairly rapid production response. We don't have to put in vast quantities of CO2 to get pressure in the reservoir up, because the pressure is already there.

We actually demonstrated that when we were drilling our development wells back in 2005, 2006. We drilled wells, and we found original bottom-hole pressure and the wells flowed on it.

So we are very bullish on response time and actually that will further reduce the amount of CO2 required to be purchased and injected in the field.

So we could see -- be surprised with a quicker response than kind of what Denbury is saying?

Denbury is a company that prides itself on delivering more than what they forecast. I think I would just leave it at that.

Okay. That's great, guys. I really appreciate the color and good work.

Joel Musante, C.K. Cooper & Company.

How you doing, guys? I just had a couple questions for you. Just first on the production rate in March. If you had those -- if those two wells were on at full production, what would your rate have been?

I don't have that at the top of my head, Joel. I couldn't tell you. It would be substantially higher, obviously; but I couldn't tell you right off the top of my head. I'm sorry.

Okay, all right.

(multiple speakers) guessing.

I also had a question about your Neptune project. This technology that you're going to use, I remember on previous calls you indicated that your goal is to decrease the water cut or increase the oil cut. But then I thought I heard you say that you expect also to enhance recovery.

So I was trying to just get a feel for -- when you talk about enhancing the economics are you talking about lower costs or are you talking about actual enhanced reserve recovery from the wells?

Sure. They're really one and the same. If you've got a well that -- conventionally you don't do anything else, will have a high water cut, because the water comes in. Water as you well know preferentially moves through rock over oil. And if you have heavier oil, then it's even more so.

So in a conventional infill well, the well will come in at a fairly nice rate of oil; and then within a matter of months or a year or whatever, water starts coming in and rapidly overtakes the oil. And you end up with 95% water production.

In fact, you remember over in Tullos in Louisiana, our old field there, we actually were producing at a -- I forget. I think it was like a 99% water cut.

99.5%.

99.5% water cut. I mean we were literally producing an ocean of water that had a few droplets of oil in it.

So as a result, the cost of producing, handling, injecting, reinjecting that water is very high, and your economic limit cuts your production off at an early life.

If you can use this technology and say instead of 0.5% oil cut, but you get 5% or 10% oil cut for a longer period of time, you postpone reaching that economic limit and therefore increase your recovery. That is how we say that we use this for Enhanced Oil Recovery. Well, it is enhanced in the sense that we are getting more recovery than you otherwise would get.

Okay. That makes a lot of sense.

We're not doing anything in the reservoir itself per se. We're not injecting anything, we are not injecting chemicals, we are not -- anything of that type, it's just --

It's a mechanical device you put in the well.

There's a lot of mechanical jewelry in the hole that allows us to do things differently to enhance the amount of oil cut versus water.

Okay, all right. Then just to ask a question about the Woodford, the deeper part of the Woodford. I thought I had some notes about you -- or another operator drilled a well there and I think it came on around 1 million a day.

Right. Our Woodford really has two parts to it. We have a shallow part in Wagner County, which is roughly 1,500 feet. Then we have a second part which is in Haskell County; and that area of the Woodford is in the 4,000 to 5,000 foot depth range.

Haskell County acreage is the one that was offset by that one well that was drilled a year and a half ago. It came on at a 1 million cubic feet per day rate from about a 2,000-foot lateral at a depth of, I think, 5,000 feet.

We have production data for its first year of production. It was a very steady production rate, a very steady decline. After a year it was still making between 600 and 700 Mcf a day. When you plot it up on the standard Shale gas plotting simu log rate versus cume, it was a straight line that says it's going to make about 1 Bcf of reserves from 2,000 feet. And that is our go-by for the Haskell County acreage.

We actually expect that we will be drilling longer laterals, probably in the 3,000 to 4,000-foot range, which suggests a target of perhaps 1.5 plus Bcf per well.

So that is a different play, but it's still the same concept. It's shallow enough that we believe we can do the vertical section air drilling. We believe that we are out of any significant faulting area, so we don't have to do 3-D seismic.

We don't have to do high-pressure hydraulic fracs. We can keep these at very minimal pressure. Therefore, we can use second-tier frac companies and lower horsepower. So all of our costs are almost exponentially less.

So what would the cost for a well in that area be? I know costs have come down.

We are targeting in that area F&D costs of anywhere from $1.00 to $1.30 per Mcf.

Okay. So would that -- is that based on the Bcf from that well? Or do you have some more conservative estimate?

It's based on roughly a 1.5 Bcf gross per well and an approximate $1.5 million completed well cost.

Okay.

Now, that number is a couple months old. I mean, early '09.

All right, so the fact that you had like a shorter lateral, you'd probably drill a longer lateral and would get through more?

We anticipate we would go after a little longer lateral, 3,000 to 4,000 feet. And that is our well cost that we had estimated, associated with that longer lateral.

Okay. As far as the more shallow zones there, you said you were monitoring that well in the deeper zone. So what has the -- has the production data from those other wells in the shallow area, has that kind of panned out to what you are expecting, that kind of 30 Mcf a day initially, rising up to maybe 70 Mcf a day over time?

We have quite a bit of data that we are looking at in the Wagner County area, which is a shallow area. We have -- there's actually three different operators that we're following. All are private companies and so obviously you are limited to the data that is publicly released, which typically runs very late. But there has been at least 60 wells if not more drilled and completed in that shallow Woodford on basically three sides of our acreage -- to the East, to the Northeast, and then directly to the West.

Now most of those wells have been drilled at a much more shallow depth around 800 to 1,000 feet whereas ours are about 1,500 feet. So we expect to have much better pressure than them.

Their wells, the initial production rates they've reported have been, as you said, the 30 Mcf all the way up to I think averaging closer to 100 Mcf a day range. The well to the West I believe was about 150 Mcf a day range.

This is, we believe, a biogenic play. You are going to have some dewatering. You're going to have an inclining production rate, we believe. So you won't see your peak rate until several months after you put the well on.

Our economic modeling is all based on peak rate per well on the order of about 70 to 80 Mcf a day and then declining from there. So we think we are being fairly reasonable and conservative in our numbers. And that's how we get to our 200 to 300 million cubic feet per well target recovery number.

Okay. All right.

[I lost that] data there.

Well, that's all I had. I appreciate it, guys.

Richard Rossi, Wunderlich Securities.

Morning, everybody. You covered most everything, but a couple things. Are those two wells that were off in part of March, are they back on production?

Yes.

But production will still be down in the fourth fiscal?

Well, I mean, keep in mind that these wells all have high rates and then they decline.

Right.

Now (multiple speakers) wells we drilled last year, they are all fairly stable, stabilized rates. These two wells, they are approaching their stabilized level of production.

The one well, the Pearson, the problem we've had with that well is not that the well is an issue; it is just that it produces into a gas line where there is not a lot of capacity. So our well has put them right at max capacity and straining their system and their compressor. So anything that they do ripples right back up and it affects our well.

Especially in the chalk, steady-state is very important. And if you start going up and down, up and down, that wreaks havoc with trying to have a stable production rate out of your well. So we've had to do a lot of tinkering with the well, just constant monitoring, because every time their compressor goes down, we have got to go out and get our well stabilized again.

So we believe that they have completed their compressor work. We are back online and we are getting it back to a stable production level again. But I can't tell you that we won't have future issues with this.

Okay, all right. Then the only other thing -- because you have covered most everything -- is that G&A run rate the rate going forward?

No, it is not.

Yes, we didn't highlight that, Rich. There's a couple things that are hopefully favorable. One is, we didn't mention -- we may have mentioned it in the press release someplace. But our FTEs are down by three, one contract and two employees, and we are going to keep it that way.

Okay.

So that will have some effect. Secondly, our legal fees are kind of high right now, and we hope to be concluding one of those issues that has been driving it pretty heavily. But we still don't know yet when that expense is going to stop. Soon, we hope.

Okay. Then just the final thing. It seems obvious that whatever your CapEx plans for fiscal 2010 are, that they are very, very likely to be back-end loaded. Is that fair?

At the moment, 2010 CapEx program is likely to be heavily focused on drilling these cheap shallow wells and re-entries in Oklahoma, plus a number of wells in South Texas, which again those are fairly reasonably low cost. Which allows us to get a lot of wells down without spending a lot of money.

At the moment, absent a major shift in commodity -- well, not major -- a significant shift in commodity prices it is hard for us to get real excited about going out and doing a $1 million or $1.5 million reentry in Giddings.

Agreed. I mean --

Remember, Giddings is a statistical play. You can't count on any one well to hit an average. You have to drill multiple wells to make sure you get your average.

Right.

So if we say, oh, we're going to drill one well in Giddings -- well, that might be a great well or it may not be a great well. So do you really want to risk a major portion of your working capital on that?

So we're going to be very cautious in how we go forward. We may look at what other ways do we have of developing value in Giddings.

Okay. Well that's about it for me. Thanks.

Brad Shoup, Armstrong Equity.

Hey, guys. I think most of my questions have been answered. Let me see here. Oh, on your comments on the Delhi about the history there and the recovery and the pressure maintenance, do you know what the recovery percentage has been historically from the primary and secondary?

We know what the overall recovery has been. It is roughly 190 million barrels of oil. That is the numerator.

Now the denominator depends on who you talk to. We've heard numbers ranging from 350 to up to 500 million barrels.

Okay.

So, as a result, what you say is the recovery to date has been maybe 50% to 40%. And I think that is reflective of how good a quality reservoir it is, that with that kind of work to date that they've gotten that much oil out of the ground.

Yes.

Of course, the bottom line in oil and gas recovery is that the better the reservoir, the better the recovery. So if you look at a reservoir that has only recovered 10%, well that doesn't mean you've got 60% or 50% to recover. It means that if your primary was 10% you can maybe eke out another 10% or 15% or 20% with all the work that you do.

But the more oil you get out in primary, the more oil you are going to get in the secondary and tertiary.

Okay. What is the kind of range of impact that you could get from the royalty interest in 2010? I am just looking ahead to your ability to spend CapEx without borrowing in 2010. Will the royalty be significant enough that it will give you a few million dollars to bolster your budget in 2010?

That is very speculative at this point, and it's a number that we don't have any control over whatsoever.

Sure.

I would hope that we could generate something in the seven-digit range that would fall directly to our bottom line and be available -- after tax, obviously -- to invest in 2010.

Now whether it's a $1 million number or a $2 million or $3 million, that would be pure speculation on my part.

Okay. That's kind of the range I was looking at.

The bottom line is if you look at Denbury's position, they've got over $0.25 billion invested in this project. They have every reason and incentive to accelerate the rollout as fast as possible. Prudent, obviously, to what information they get as they expand and get this response and go forward.

So there is every reason to believe that the development will be accelerated. But that's -- we are just along for the ride there.

Yes, so they've got this original 50 wells that will be brought on sometime towards the end of the year; and then we don't know too much about when they are going to drill the second tranche and the third tranche of wells to roll this thing out. But we know in general it will happen over four or five years; but we don't know if it will be front-end loaded or not at this point. Is that fair to say?

I think for the most part. Again, if I were their project manager, I would be wanting to take results of the first phase, and then I would be doing -- rolling it out as fast as I could.

Again, that is how they get their ROI up. That is how they get their proved reserves up. That's how they get their cash flow up. There is no sense whatsoever in delaying that, unless oil prices obviously were not to cooperate.

If oil prices went down to the $30s, they might say -- they might take the same approach that we take in our business, which is -- why produce oil at $35 if we think it's going to be $60 the next year?

Okay.

And you know, they have a totally different situation than we are. There's not many companies like us that have the luxury of saying I'm not going to drill wells because it doesn't make sense. We don't have debt that we have to maintain or service.

The Giddings reserves last year were 24 Bcfe at June 30. We've drilled a couple of wells this year and produced some. I guess I'm trying to get just a handle on -- do you expect that number to go down or up at year-end, June?

Yes. Brad, I really don't know. It's going to be a function of what prices are on June 1. I mean July 1. It's going to be a function of the [ASEs] that we prepare for those PUDs.

Okay.

There's just so many things that factor into that that are still floating around out there, that I couldn't begin to tell you what the impact is going to be.

Obviously, the reserves we had on July 1 of last year accommodated an oil price of $140 and gas of $13. So to the extent that we are way, way, way south of that, it would be reasonable to expect some impact.

Yes, okay. In terms of the wells that you drilled, did your opinion of your acreage there change over the year? Did you learn anything from those wells?

Or was it just sort of just business as usual; you're just two wells more into the development than you were at year-end last year?

I guess to answer that we would have to go back and look at the whole development from day one. We first drilled six wells last year. The results in one area of our acreage were less than what we expected. That was in the Fayette County area. As a result of that -- and we had really good results in other areas.

As a result of that, our July 1 report of last year reflected a change in our portfolio. We downgraded and removed locations in that Fayette County area and replaced them with locations in the better areas.

The two wells that we drilled are examples of that high-grade. So is it fair to use two data points in the Giddings Field to suggest that things reflect an improvement in that portfolio? Perhaps. I'm not going to stick my neck out too far in that kind of a statement.

Obviously, we're very pleased with the results of those two wells. Obviously, they are as good or better than originally anticipated. We would like to believe that that is reflective of our current portfolio. But until we drill some more, I couldn't say that for sure.

But yes, we are very pleased with it and it gives us more comfort, obviously, to what we have left in our portfolio of 25 PUDs. And we have a few more locations that we've got now leased up that may or may not be added to our mix.

Okay, one last thing. I looked at the -- I got the well reports from Oklahoma for the guys that offset you there in Oklahoma, and was looking through. I think there's over 100 wells that have been drilled by just two of the operators, anyway.

It looked like on the -- as I looked at the map, that the ones that were located on kind of the southern end of their acreage, which would be -- you said before that you are deeper than they are so you're South of them, I guess, in general -- were some of their better wells. Some of them got up in the 200, 300, and one of them was even 500 Mcf a day at least as a reported IP rate.

So I'm cautiously optimistic that you're lowballing us with the 70 or 100 a day. We'll see. We won't know till you drill them, I guess, but --.

(multiple speakers) your advertisement for us. We try to follow the Denbury mode of under-promising and over-delivering.

Okay, well, we'll see.

That's right. The proof is in the pudding.

All right. That's all I've got. Thanks a lot.

Kelly Loyd, JVL Advisors.

Actually it's John Lovoi. How are you, Robert?

Hi, John.

How's it going? I had a couple questions. So I think you answered one. So we've got 25 PUDs more in Giddings.

I think the last time I talked to you, you guys were at least thinking about adding some acreage. Did you pick up any more acreage in that play?

Well, we have 25 PUDs remaining from those that were on our reserve list as of July 1 of last year. And we had additional locations which we had not completed the leasing on as of that report, that we have subsequently completed leasing. Now whether or not they get added is obviously up to our independent reservoir engineer. He has yet to say grace on them, so whether or not they get added I couldn't say for sure.

Sort of ballpark what is the -- is it 20% more in potential inventory, or --?

A few more, let's just say that.

Okay. What do you think the current drilling complete is on those wells?

Well, we have -- our whole portfolio in total has really three pieces to it. We have reentries that are a pure reentry that we don't have to redrill the vertical section. Those typically cost about $1 million.

We have a second category of reentry, which is a reentry from surface casing. That example was like our Hilton well we just drilled, where we actually have to redrill most of that vertical section. Those typically are about $1.5 million plus, $1.7 million. $1.5 million to $1.7 million. The Hilton actually cost us over $2 million but that was because it was drilled using costs that were in place last fall.

And then we have our grassroot wells. That's where you're actually starting from scratch from the surface and you're going typically further out laterally. You are doing one -- typically you're doing two lateral sections. Total horizontal footage is on the order of 5,000 to 8,000 feet. Those wells run anywhere from the low 2s to as much as $3.5 million per well.

The locations that we are likely to add are more likely going to be in the lower-cost reentry range.

Okay. So would it be fair to say that on a blended basis those 25 or 27 PUDs that you're going to have are about $1.75 million?

Some of them are (multiple speakers)

You are talking about mixing grassroots and reentry. So --

Yes, but I'm saying of the PUDs some are grassroot, some are reentry, right? So I am just trying to get sort of a blended.

Well, we have -- of the 25 locations right now, 11 are grassroots and 14 are reentries.

All right. I can sort of ballpark that then. So when I look at your -- so sort of the current reserve picture for you guys is right now plus or minus 4 million barrels. Is that still right?

4 million in the proved reserves on that July 1 report; plus another 3.1 million of probable reserves associated with that same Giddings Field area. A lot of our grassroot PUDs have both proved and probable reserves associated with them.

Right. So when I look at your current reserve picture, if I were to say if eventually all that gets moved into the highest reserve category, you've got 7 or 8 million barrels likely to come out Giddings?

Again that is going to be subject to oil and gas price.

Sure.

Those locations are primarily gas wells; and they may or may not be kept in the report this coming July 1 if gas prices stay where they are.

Right. Okay. Then in Oklahoma for the shallow -- what is the breakdown between what you call the shallow acreage and the deeper acreage?

In the Wagner County area, which is the shallow acreage, we have 9,300 net acres. In the Haskell area, which is the deeper area, we have 8,300 acres, net acres.

Now that is scattered in the sense that it's not all block acreage. It's fairly concise, but more than likely we will be able to add substantial amounts of acres through forced pooling. For example, we may have a well that we drill that we will go in and file for a unit of 640 acres. We may own 300 of that and then through forced pooling we will get the balance or a portion of the balance.

Right. What -- just ballpark, the forced pooling could increase your overall acreage by 25%, or --?

That is probably not a bad ballpark estimate.

Okay, and on the shallow stuff, would the shallow that you are testing vertically, do you envision a -- if in fact you went into a full development or sold it to somebody that assumed a full development, would it be produced vertically? Or are they going to do those horizontally?

We would anticipate that the shallow area is going to be drilled and developed on a vertical basis. I think initially we will target 20-acre spacing. I can see it getting down less than that.

Okay, and you're sort of -- I think you mentioned the recoveries you were anticipating based on very limited data were 200 to 300 million per well.

Right.

Okay. Then what about for the deeper stuff. Again, it's early days; but is that going to be more on 160s, 320s?

Well, obviously you start at 640s then you work your way down, just like in all those shale plays. Arnett, they are down to 20 acres and that is at 8,000, 9,000-foot depth.

Our initial target is probably to get it down to 80-acre spacing with expectations of taking it down to 40 acres. I guess eventually you could go down less than that.

But 40 to 80-acre spacing I think is a very reasonable target, which suggests somewhere in the neighborhood of -- what, 100 to 200 wells?

Right, and you are -- again preliminary you guys were kind of type curving --

We had B and a half.

B and a half, okay. Got it. Okay, and then I don't know how much information you guys have put out on Neptune. But is there a -- assuming your theory is successful, I guess you got sort of two scenarios here. One is just infill drill and do what they were doing back in the '90s, maybe a little bit better. What is the just sort of ballpark anticipated reserve recovery or reserve potential, however you want to put it? I'm not holding you to these numbers, and I will make my own price forecast.

But just kind of -- if I were going to make the assumption that oil was $50 to $100 for the next five years, what sort of reserves would you think on a reasonable success, without the technology, you would be able to capture?

In the field, the historical infills that we are going to be emulating recovered I believe an average of 25,000 barrels per well.

Okay, and how many locations do you have?

We have 1,500 net acres; and we're talking about going to 10-acre spacing. So obviously there's already wells there, so we are infilling the other wells.

So I think a reasonable target would be somewhere between 50 and 70 locations.

Okay. Then do you -- with your -- assuming your technology is value added, does that double that 25,000 per well?

I would really, really hesitate to even hazard a guess there.

Okay, okay. But I mean obviously you view it as a value-added thing.

Sure.

So if I wanted to hazard a guess I might say a 50% improvement and --

But what do you think it changes the oil cut to, from no technology applications?

My partner is asking what would be the change in oil cut you would anticipate with the technology?

When we did this test in Louisiana, we took a well that was -- an area that was generating 0.5% oil cut; and the well that we put this on was like 5% oil cut. Now that was an area that had been drilled down to 1 and 2-acre spacing and we found that the oil reservoir had been just about washed clean of oil.

Now I'm not going to tell you that that is what we will see. That is part of the --

I think we've got -- that's enough, Bob. I think we understand that.

It is -- we're still early in that. We are in an R&D mode for that technology, and therefore quantifying it is dangerous for us to say.

Hey, Bob. This is Mike Raleigh. I've got a real boring technical question. Do you have an idea of what the average water saturation was in the Delhi unit? I mean originally.

Oh, boy. You caught me by surprise on that one. Not off the top of my head.

Well I guess the more layman's way of asking the question is that -- what was a little bit enlightening to us on this call was that it has not been waterflooded yet; and therefore you would assume that the sweep with CO2 would be substantially better than the typical CO2 which follows a waterflood.

I think it would be -- it's possible, let's put it that way. Keep in mind it is also a very high-quality reservoir, fairly decent homogeneous properties. So I don't know that we are talking about a huge improvement.

But I think it's possible that instead of -- well, Denbury averages about a 17% incremental recovery of oil in place with their CO2 floods. They've gotten as high as 19% and 20%.

I think instead of -- in our numbers we put out, we used 15% recovery. So I guess what I'm saying is that we see that the margin for error on ultimate recovery is to the upside or more heavily weighted to the upside because of all these factors.

Why is there such a variance in the estimate of the original oil in the play?

It's a big reservoir, it's a big field. It covers 21 square miles. Well density is about every 40 acres. There is a lot of questions on where is the original oil-water contact.

Okay. One more question; I don't want to belabor this, but did -- was there a lot of water production from the wells when they were doing the pressure maintenance downdip? Or was it just sort of going largely --?

If I recall correctly, they injected about 700 million barrels of water and produced 500 million. Now obviously the difference between the two is the oil that they removed, which is why they reservoir pressure is still pretty close to original bottom-hole pressure.

Okay, but I guess I understood that it wasn't a whole lot of waterflooding in the field.

There is a lot of pressure maintenance. They injected a whole bunch of water into the reservoir. Then as the oil producers at the low end of the field started to water out, you started having a higher water cut. Then they would produce those until they got to a sufficiently high water cut that they would then either shut those down or convert those into injection.

Okay, I got it.

Okay, Bob, and then as just a last question, do you guys have anything else in the inventory that is kind of -- that you're working on right now that was sort of where maybe Neptune was a half a year ago or so? Or is the focus going to be on these really four projects? Not that you're going to have a big role in Delhi.

We have other -- yes. Our particular expertise as a Company and as a team is to generate project concepts and implement those projects. Obviously, we have a pipeline of things that we are looking at, some we put more effort into others. So yes, there are other things that we are looking at.

Now, what we don't have is that we had before is a huge pile of cash to fund large-scale acreage purchases, so we have to be much more targeted in what we do. So I'm not going to tell you that we have another Oklahoma Shale project in us because we don't have the money to go out and buy 18,000 acres with.

Right. I guess where I was headed with that was like, for example, if you looked at -- say you apply this technology in Neptune, you have a very favorable response like you saw in the prior project, are there a number of other of these types of fields that you (multiple speakers)?

There are other opportunities and that would be an area that we would have the ability to acquire other areas, other projects, because the amount of acreage is a whole lot less. Like at Neptune we only have 1,500 acres. The cost of purchasing that acreage was fairly minor compared to, for example, in Oklahoma or in Giddings.

Got it. Okay. Well, fantastic. Thanks for taking all the time.

No problem, John. Thanks.

[John Kohler], private investor.

Good morning. Question, a sort of follow-on. If you look at the potential opportunities for Neptune-like projects and you look at Giddings and you look at Woodford and Oklahoma, would you -- how do you look at capital allocation going forward? Are those -- nothing is a sacred cow, I'm going to guess. But what type of environment would you need in order to sell those assets and redeploy those into other opportunities that would be perhaps cheaper to fund?

Well, one thing that you have to keep in mind is -- what are we trying to accomplish with the Company? Assets like Delhi and Oklahoma we consider to be core assets that we really do not want to sell off, at least not in totality, because they represent such a large portion of our value. And any sale of them would generate tremendous tax obligations, that then to transfer that value to the shareholder you start doubling up on tax.

Right.

Now a smaller asset, we have absolutely no compunction about monetizing them if we feel that we can do so and get more value than by keeping them and redeploying them. So we're always considering what is the best way to use our capital, to use those assets.

On capital allocation going forward, our key here is we want to make sure that we can reap the full value out of Delhi in Oklahoma. To do that we need to make sure the Company is around and able to get that value and not be forced into a premature sale, monetization, whatever.

So we have great financial stability now, no debt and a lot of working capital. And we want to make sure that we retain that position going forward, because that is the leverage that allows you to get the best value down the road.

That being said, we do have the ability, we do believe we have some excess liquidity that we can allocate to these other projects. And that is the nice thing about Oklahoma and the South Texas, it is that we can do a lot of things there on a per-well basis that doesn't cost us that much.

Giddings is a little more of an issue, because those wells do cost. Even the reentries are a $1 million reentry, and you have to do more than one to make sure that you're successful. As a result, that is an area that we are going to be much more careful in how we spend our money.

Okay, great. Then I guess if you look at the Woodford and Oklahoma assets, it could be setting up timewise that you may see an increase in gas prices on -- more than just a pop say, in the next year. How fast would you be willing to accelerate drilling there, production?

I think the pace of development there would be a function of, as you said, gas price. It's going to be a function of how much of our liquidity we are willing to devote and whether or not we would be willing to or would have available to us project financing to expand that effort that would not put our other assets at risk or adversely impact our shareholders through severe dilution.

Great. Thanks very much.

Brad Shoup, Armstrong Equity.

Hey. I just wanted -- I've got a well model on this shallow Woodford stuff that I am trying to develop. I am using 20% royalty and $1 LOE and a $1 differential. Are those reasonable assumptions?

I think that the LOE cost is probably going to be less. These are shallow wells. We don't have to do a lot of fancy treating on them. The differential is probably not bad on a long-term basis.

Okay. And what about severance in Oklahoma? is it like -- ad valorem and severance?

I think the severance in Oklahoma is like 6%.

Okay, and --?

Ad valorem is typically a couple percent.

Okay. What about in Delhi? I don't think I've ever followed up on that. Is the severance and ad valorem higher for the Delhi project?

Severance tax in Louisiana has a graduated basis, based on the status of the oil producing well. Oil severance tax is 12.5%. Once a well drops below 25 barrels a day on average on a lease, it drops to 6.25%. Then when it goes below 10, it drops to 3 1/8%. However, Louisiana abates severance tax on tertiary projects until the project pays out.

Okay, okay. That's good news. Okay. Thanks a lot.

Thank you. At that this time there are no further questions in the queue. I would like to turn the conference back over to management for any closing remarks. Please continue.

Thanks to everyone for participating today. Excellent questions, as usual.

With all this, I would like to thank you for your time this morning and feel free to call for any questions you have on what we've discussed today or put out in the press release. Thank you and good morning.

Ladies and gentlemen, this does conclude the Evolution Petroleum's third-quarter earnings conference call. This conference will be available for replay after 12 p.m. Eastern Standard Time today through May 21 at midnight. You may access the replay system at any time by dialing 303-590-3030 or 1-800-406-7325 with the access code of 4074414 pound.

Thank you for your participation and at this time you may now disconnect.