Evolution Petroleum Corporation (EPM) Q3 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Evolution's Third Quarter of Fiscal Year 2011 Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Thursday, May 12, 2011. And I'd now like to turn the conference over to Ms. Lisa Elliott of DRG&E. Please go ahead, ma'am.

Thank you, Elissa, and good morning, everyone. We appreciate you joining us for Evolution Petroleum's quarterly conference call to discuss the results of the third quarter of fiscal 2011 which ended March 31. In a moment, I'll turn the call over to management, but I first have a couple of items to cover. If you'd like to be on the company's email distribution list to receive future news releases, please feel free to let me know. My contact information is in the earnings release that Evolution put out this morning. If you wish to listen to a replay of today's call, it will be available in a few hours and archived for one year via webcast by going to the company's website at www.evolutionpetroleum.com, or via recorded telephone replay until May 19. That dial-in number and passcode can also be found in the earnings release. Information recorded on the call today is valid only as of today, May 12, 2011, 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 may contain forward-looking information which are based on management's beliefs, as well as assumptions made by management and information currently available to them. Forward-looking information includes statements regarding expected future drilling results, production and expenses. Although management believes that these 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 and uncertainties and assumptions which are listed and described in the company's filings with the Securities and Exchange Commission. If one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected. Also, today's call may include discussion of probable or possible reserves or use terms like volume, reserve potential or recoverable reserves. Please note that these estimates are of non-proved reserves or resources that are by their very nature more speculative than estimates of proved resources or reserves, and accordingly, are subject to greater risks. Now with that, I'd like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer and -- Bob?

Thanks, Lisa. Good morning to everyone. We certainly appreciate you joining our call today and spending the time with us. I'll briefly review some key operating results, then Sterling McDonald, our CFO, who is here this morning, will go over some select financial information. Then I'll come back and go over our future plans and then we can take your questions. Hopefully, you've had a chance to review the earnings release we put out this morning, and you read that we reported strong earnings for the quarter, primarily due to a more than doubling of sales volumes from our Delhi Field project during the fiscal third quarter, as well as higher oil prices. The 113% increase in Delhi sales volumes over the immediately prior quarter for gross average daily rate of 2,003 barrels of oil per day was all -- almost all entirely from Phase 1, which is the smallest phase of the project. Our net production currently comes from our 7.4% royalty interest, which has a big impact on our bottom line, because it doesn't carry any operating costs. We also don't carry severance tax for the time being due to the project being qualified by the State of Louisiana as a tertiary project. Now although the project is just starting to ramp up its production profile, that production has still enabled us to turn the corner on profitability, and we should continue to see our cash flow from Delhi grow and fund our other projects. We're very pleased that Phase 1 at Delhi is continuing to produce ahead of schedule and better than expected. Please note that the Delhi is still at a very early stage, with about 98% of its production from Phase 1 out of a total of 6 phases, and that didn't even include the 4 additional reservoirs that were added to the project reserves last summer are in our probable category. Phase 2 and the remaining phases are about twice the size of Phase I, and we begin CO2 injection for Phase 2 at the end of November -- December of 2010. We expected that, that oil response would occur in the middle of this year. However, just by Phase 1, we achieved early oil response in March of this year, and that did contribute to quarter 3 sales. We should see continued oil sales growth throughout calendar 2011 due to the Phase 2 contributions. Additionally, Denbury, the fields operator, is currently rolling out Phase 3 at Delhi, with first CO2 injection expected during this year and meaningful contribution to sales by 2012. The current schedule provides for one new phase of development essentially about every year until the project is fully installed. Now since the Delhi EOR project was initiated in 2006 and first CO2 injection began in 2009, the project has consistently outperformed our expectation. In addition, we are benefiting from higher than originally projected oil prices and premium pricing compared to oilfields in most other states due to the location and ability to transport our sales volumes by pipeline all the way to the refinery. Transport by pipeline eliminates a considerable trucking charge and moves our oil to a market that's materially supplied by imported oil. As a result, our Delhi oil sales carried a 12% premium in realized price over our Giddings oil sales in Central Texas during the quarter, for example. Now while Delhi cash flows ramp up, we are moving forward with operations to de-risk and define the potential in our unconventional gas project in Eastern Oklahoma. During the third quarter, we focused on our substantial acreage position in Haskell County which we think has bigger potential compared to our shallower projects in Haskell -- excuse me, in Wagoner County. Currently, we are continuing to test the 5,000-foot deep formations in the John Wells #1 well in Haskell County, a vertical well that we reentered in the second fiscal quarter. As you might recall, we wanted to let that well de-water and produce unstimulated for a bit before proceeding with the single-stage frac similar to comparable wells in the area that we are modeling. The frac job is now scheduled to occur this month. Results from this well and a second test well will allow us to design a full-scale development program for the 30 sections of land in which we have significant leasehold position. Current activity on our second vertical test is right now focused on unitizing the 640-acre section around the well before we commit to field operations. Now the unitization process allows us to acquire other mineral lease owners within that 640-acre section to lease, farm out or participate under defined terms, and thereby, likely increase our net leasehold position. We're hopeful this process will be completed soon, and we can get the well test -- second well tested sometime this summer. Now we were not particularly active in our Wagoner County area due to the decision to focus on the higher potential in Haskell County of Oklahoma. Our leasehold and the successfully tested block at Wagoner is being maintained, while we're allowing certain leases in other blocks to run out. Development activities at our Giddings Field continued through our ongoing industry joint venture in which we drilled 3 wells to date. During the third quarter, we completed infrastructure of the pipelines for second and third JV wells, including extensive gas sales lines for the Dodd #1, the most recent well, in addition to a saltwater disposal pipeline connection. The Lightsey-Lightsey #1, which is our second well, was put on production in early February, had initial flowing rate of 124 barrels of oil and 1.2 million cubic feet per day. It's now on our official list as stabilized rate of about 75 barrels of oil equivalent per day. The Dodd was put on production in early April at a pipeline-constrained flowing rate of about 2.7 million cubic feet a day or about 17 barrels of oil, and it appears to be the best well that we have drilled to date in the Giddings Field. Now the Dodd is the second well that we have drilled in our Grimes County leasehold. The first was the Pearson well that had been our best well to date prior to the Dodd. We have 4 other leased locations on our Grimes leasehold. To date, our share of capital expenditures in the JV program of 3 wells is less than $1 million. We own 100% of the working interest in the Pearson well and the remaining locations and we own a 20% working interest before payout, 38% after payout, in the Lightsey and Dodd wells. Our JV partner has the right to elect selection of one of our remaining Grimes location for a JV during the program. We plan to complete the first JV well, the Supak-Brinkman, into another reservoir later this year. Now recently, we submitted drilling proposals to our JV partner for the fourth and fifth wells. Now these are optional by our partner, and the proposals are still outstanding. Regardless to how they decide to proceed, we are exploring opportunities to enter into a second JV to develop some or all of our remaining Giddings Field drilling locations that we have leased. Now overall, our production in the Giddings Field stand about 45% compared to the quarter of a year ago, and this is due to normal field decline and the temporary lost production from the Pearson well. The Pearson was restored to production during this recent quarter to its previous level. Sequentially, our Giddings Field production is fairly steady, with Lightsey-Lightsey beginning to contribute production in early February. We expect higher volumes in our fiscal fourth quarter as it contributes for the entire quarter at its current stable rate in addition to the Dodd that began production in early April. I'm pleased that our study effort to commercialize our artificial lift technology appears to be moving forward. We believe that we have reached agreement on principal terms with our first JV partner, and we hope to submit fieldwork this summer. Furthermore, we have trademarked the technology under the name of GARP, standing for Gas-Assisted Rod Pump. Now, with all that, I’m going to turn it over to Sterling to talk about some of the numbers.

Thanks, Bob, and good morning. Before we look at the financial components, I'd like to point out a few housekeeping items regarding the reporting of our Delhi operations. I know this may be old hat to many of you, but there seems to be some confusion in the public's understanding of our relationship with the operator at Delhi. First, we know that many of you track our operators’ Delhi activity. As is common for U.S. oil and gas operations following GAAP, each of the working and royalty interest owners separately report their net production and net sales volumes. Those nets being the owner's percentage interest times the gross field production or gross field sales volumes. The point I want to make here is that for financial reporting purposes, one cannot take our 7.4% royalty times Denbury's financially reported net sales or net production volumes. Rather, our net sales are 7.4% of gross field sales, not 7.4% of Denbury's net sales. Occasionally, we will offer you total gross production or sales numbers in our discussions, and we try to label it as such. Otherwise, the volumes we present are considered net to our interest. Rarely, if ever, do we discuss Denbury's net revenue or production numbers. Secondly, our 7.4% royalty interest doesn't convert to a 24% working interest with an associated 19% net revenue interest at payout. Rather, these pieces are added to the payout, resulting in our ownership of the 26.5% net revenue interest bearing 24% of the cost after payout is reached. Thirdly, Denbury tends to place hedges on their production from time to time. These actions are only relevant to their share of production, and they in no way affect the prices we receive for the share -- for our share of production. With that said, let's move on to the financial results. Evolution reported this morning, what can I say, it was a very clean quarter. We have very little to complain about. Net income turned positive to $170,000 in the current quarter compared to a $460,000 net loss from the sequentially prior quarter and a $550,000 net loss in the year-ago quarter. Similarly, losses narrowed 60% in the most recent 9-month period. Improvements in the current quarter were driven by a significant increase in higher valued oil production, contributions from our Giddings joint venture, an increase in average prices we received per BOE and a 14% reduction in operating expenses, which include a 75% reduction in our depletion rate per BOE of sale. Interestingly, net production growth wasn't what drove our 71% revenue growth over the prior quarter and our 56% revenue growth over the prior-year quarter. Rather, it was a change in our revenue mix. Sales volumes continued their trend toward more oil, with liquid volumes, predominantly crude oil, accounting for 73% of BOE sales volumes during the quarter compared to 65% in the prior quarter and 43% in the year-ago quarter. The blended product prices we received in the third quarter of '11 increased 31% sequentially from the prior quarter and increased 55% over the year-ago quarter. Field margins continued to improve, almost $55 per BOE in the third quarter of fiscal '11 compared to $34 in the prior quarter and about $14 in the third quarter of fiscal '10. We also held our working capital steady at $3.1 million as of March 31, 2011, which compared to working capital of $3.2 million on December 31, 2010. Working capital actually troughed during January 2011 and has been rebuilding since. We continue to be debt-free. [indescribable] what do we have to expect looking forward, and what do we worry about? Absent an increase in our $4 million capital budget for the remainder of our current fiscal year, which is over in June, temporary production pullbacks from our properties or a major decline in product prices, some little ones of which we're seeing this morning and yesterday, we expect to see our working capital increase in Q4, accompanied by an increasing internal generation of funds for the foreseeable future. In our fourth fiscal quarter, we expect to see total revenue volumes increase from both Delhi and our Giddings Field, in addition to the potential for production from the John Wells that Bob mentioned, which will be fracture stimulated soon, albeit the production from the latter may be small. One other thing I want to point you to looking forward, as we've discussed on our roadshows, our entire corporate presentation, but one of the things that we focus on for Delhi is Slide 14 shows how our Delhi value increases over time. A couple of things to note about that chart, if you look out to 2016 and take the remaining PV-10 at that time based on a $76 flat price deck, and add the cash that's been harvested through production up to that point, you see that those 2 components get us over about $16 of fully dilutable share based on a PV-10 calculation. A couple of things I want to point out here. First of all, we're trading about $7 this morning. So this is over a two bagger if we were to be able to achieve trading at a PV-10 out in 2016, assuming all other factors in the reserve report comes alive, and we know there'll be adjustments here and there along the way. Probably more importantly is the $76.21 flat oil price that's embedded in this analysis. That $76 was based on pricing in effect in June 30, 2010, and did not really have a significant premium to WTI at that time. As we've reported, in the current quarter, we averaged over 112% of WTI in our sales. And if that relationship were to exist against the $76 price deck, we'd be looking at WTI of $68. So this analysis still has a great deal of cushion embedded in it for commodity price risk. So let's talk about some of the things that we do worry about. I worry about a repeat of the capital market disruptions, both as to financing risk and less so as to commodity risk, and how we can best be positioned to withstand it again if necessary. To address this, we're developing some backstop measures internally that we hope to share with you soon. These are intended to fortify us to handle any unexpected breaks like we've seen in the past. With that, I'll now turn the call back over to Bob.

Thanks, Sterling. I just wanted to reiterate some of these issues. Our reserve report that reported a year ago based on the $76 oil price which is currently about $20 less than the current oil price that we see today. And yet, at that point, that doesn't include the premium that we now receive at Delhi, which is another 10% on top of that 10%, 12%. So there's a lot of cushion between current oil price and the $276 -- $276 million PV-10 that was reported a year ago. Another thing to remember is that, that is a gross sales price. The actual margin that we receive less operating expense, when you consider a working interest growth, is less considerably less than $76. Anyway, the current oil price is generally it’s about a 1/3 increase in cash flow over the level reported in our reserve report for next year. I just want to point that out to everyone. Also, that our Giddings production commands a better price than you would get in some of the other major markets, the Southwest Texas, West Texas, the Bakken play up in North Dakota and so forth, because Giddings is still extremely close to the major refinery market. Anyway, with that, going forward, we're going to spend the balance of this fiscal 2011 completing that first test program in Oklahoma and continuing the commercialization process of our GARP technology. Subject to our partners election, we may spud a fourth JV well in Giddings, and we're considering -- continuing to consider a second development JV for the remainder of those locations. We're started working out on our CapEx plan for fiscal '12, and we expect that with that program, we're going to be very active in 3 areas. We have Giddings, East Oklahoma and then deploying our GARP technology. Growing cash flow from Delhi and continuing cash flow from Giddings should allow us a much more aggressive level of activity going forward from this point. And with that, we're ready to take questions. Operator, please open the line for questions.

[Operator Instructions] Our first question comes from the line of Phil McPherson with Global Hunter Securities.

Sterling, I think you might have been reading my mind. I was actually going to ask you questions on -- about Denbury and hedges, and what I'd like to maybe dig into is when we -- this $200 million threshold for the revisionary working interest, how do you guys audit this, and how is that number affected by Denbury hedging? Meaning, if oil is at $110 in Louisiana Lightsey right now and they're hedged at $80, are you really benefiting from the higher prices as far as the back-in occurring earlier? Or do you have kind of go along with what they hedge it at?

That's a great question. Our contract stipulates -- well actually, I was thinking about the CO2 transportation charge, which talks about field price, so I'm going to back off of that, but the answer to your question should be that Denbury's hedging activities are separate and apart from the payout calculation. I don't know that I can think of at the moment any particular point that I can put my finger on in our contract, but it's generally industry practice that hedging activities are for only the benefit of the operator, and I understand where you're going with this. It could be at the benefit of the operator relative to calculating payout possibly stretching if the price were lower, but I don't think there's anything in our oil and gas joint operating agreement that would allow for hedges to be applied to penalize or to help the revisionary working interest partner.

Generally, these days, hedges are a financial activity...

That's a good point.

As opposed to -- there used to be -- I know a couple years ago, you could actually do a hedge with your primary crude purchaser and they've got now that business now. So when you sell your oil, you're selling it at market. When you hedge, that's a financial decision that you're making which is a separate activity, and that's why financially companies have to report hedging activities separate than their revenues, so you make a profit or a loss on your hedges. So it shouldn’t have any impact that has to do with the bottom line.

I think that would be correct. Does that answer your question, Phil?

Yes. I'm trying to understand just the mechanics of -- so the oil comes out of Delhi, it’s put in the pipeline where it's metered once it goes in the pipeline, it's metered again once it comes out of the pipeline. So who is kind of like our watchdog, if you will, to report to you on a monthly or quarterly basis what the current -- I don't know if it's the right word -- account deficit or lack of deficit to get to this $200 million...

It's interesting you say that. We actually -- our Controller is sitting here, David Joe, and he just got back not that long ago from doing his regular audit that he does of Denbury's operations at Delhi Field. We examined the financials related to that field very closely in terms of what they spend, is it capital, is it operating expense, does the revenue track with the numbers that the oil purchaser reports and so forth. So we have a very close eye on that, and frankly, that was one of the reasons that back in '06 we decided that we didn't want to have our payout to be our actual payout number. We didn't want to have to worry and argue with Denbury about how much they spent, is appropriate or whatever. We just said, "Look, we’re going to have a fixed number, $200 million, period”. And once you generate revenues less operating expense of $200 million, then we back in regardless how much you spend. And that was one of the smarter things that we've done, but it makes a far, far easier audit calculation.

That's great. I know that you talked previously on one call that in the early phases of the Delhi being flooded, that you're actually -- that the account actually was growing in liability, if that's the right way to think about it, as they're incurring more expenses than they were necessarily getting out of the field. And so what production level does the field need to achieve for that number to then reverse what we're starting to come off of it, we're starting to subtract out of the pool, if you will?

I think we're there now. I think that in our opinion, that Denbury is generating positive cash flow, and therefore, that balance is starting to increase.

That's great. And so then when I run this model using just -- you can use all sorts of numbers, but it looks like you guys, your reserve report this year should be -- should use around $96 a barrel given the first -- the price of oil for the first month. We’ll need one more month here with June. So it looks like -- excuse me.

Yes. Except I think your numbers are a little on the high side.

So maybe call it $90 or whatever, but it looks like that Denbury should hit the $200 million threshold late 2013 as opposed to in your guys’ recent presentation, I think you're using 2015. So will your get -- will your reservoir engineers use that kind of calculation and put you back in earlier than what you have in the last calculation? Or how would that kind of work?

Well, there's 2 factors that go into that payout calculation. One is, obviously, the oil price, and the second is the rate of production. Now we're currently ahead of production schedule, and how that's going to be incorporated in the new reserve report, I couldn't tell you. That's in the eye of the beholder, which is in this case, the independent reservoir engineer. On the oil price part, keep in mind that while we do benefit substantially from the oil price, it's also a negative in the sense that the cost of the CO2 that we buy for injection is also tied to oil price. The cost for us CO2 is $0.20 per Mcf plus 1% of the oil price. So if today the oil price we're receiving is, for example, $100, then the price of our CO2 is $1.20. And so the benefit of higher oil prices is partially offset by the higher price we're paying for the CO2. And as you alluded to earlier, the early stages of projects you have a much higher level of purchased CO2 going into the ground. That amount will drop off starting a couple of years pretty rapidly, and will go to primarily recycled CO2 which is a far, far cheaper -- all we're paying there is just the cost of re-pressurizing and cleaning up the CO2 and put it back in the ground. So the operating costs related to CO2 will drop rapidly. But that's why when we see our models, even when I reflect the higher oil price, you don't get as nearly as much impact as you might think on advancing the payout date. Now what does have a big impact is how you accelerate production, the profile there. Now we continue to just to use what’s in the DeGolyer & MacNaughton report from a year ago, which has no acceleration. But if you do any kind of acceleration on the oil production, then that will have a measurable -- a very measurable material impact on the payout date. So right now, if you maintain the current oil price, I still think that the payout date would be advancing in 2015, and I don't see any reason for changing that until the engineers will actually give us a better production schedule, and they're going to have to just to match current production today. But how much they -- how much more they honor that, I couldn't tell you.

You might gain a little bit, but it's just too early to say how much?

Yes. Really, it would be very dangerous for me to try and speculate on that. I feel pretty confident absent a major change in oil price that it will be at least in 2015, and frankly, that's not that long from now. And the other thing to keep in mind is that the override, because it bears no OpEx is really almost as valuable as the back-in.

Right. And when you do your report with D&M, are you at liberty to kind of give us what the field looks like from a production standpoint, like what it looks like from an exit rate this year, next year, the following year? Can you kind of give us a guideline what these models are based off of so we can tighten up our kind of field model?

Well, the current D&M report has a peak rate occurring in like 2016, and I want to say it's, what, 12,000 or 14,000 barrels a day, gross rate. The safest thing to do is you just take a starting point in early 2010 and just do a linear of a lumpy increase from that point to 2016, and frankly, I don't know how you could get a better projection at this point in time. That's probably be fairly close to what's in the D&M report. It shows every phase coming on, on an annual basis.

Yes, because I think I was using 10,000 as a peak. And then it should plateau for kind of 3 or 4 years and then just start a methodical decline, correct?

Correct. And keep in mind, each phase has its own curve of that type. And so really what you're doing is you're layering on 6 different curves that have that rapid increase flat and then some sort of a decline. And so when you add all 6 together, you get more of a gentle bell curve.

Great. And on that chart that you have on Page 16 that shows kind of the revisionary interest in the cash flow, I was curious that as Denbury does Phases 3 through 6, do you -- does the -- are those phases completed before your revisionary working interest comes in? Or do you have some CapEx associated in those out years that you would have to spend above your LOE costs?

D&M report shows that we bear no CapEx whatsoever related to any of our proved reserves, that all CapEx spending is completed before the payout occurs. Now what we do have to bear is a small amount of CapEx related to certain of our probable reserves related to those 4 additional reservoirs that we added to the project last summer. And keep in mind that the Denbury has not added those into their reserves. We have in ours, but all 4 of those are in the probable category, and they actually don't have a lot of impact on present value at this time because they don't actually get installed, until the late -- latter part of the decade, and therefore, they don't have measurable contributions for probably 8 or 9 years. So when you PV-10 that, it doesn’t really have a whole lot of impact. But that's the beauty about this project, is the PV-10 is a horrible way to measure the value, I mean if you look at today the PV-10, even if you strip out all the cash flow on a annual basis, you still end up with 40%, 50% more PV-10 in 5 years. That's always been the unique thing about this project and this asset and our company is that we don't have to lift a finger, spend $1 and our PV-10 goes up by 40%-50%.

Great. And do you think you'll -- with a higher price, will you get a bump up in absolute reserves on the D&M report? I mean, it looks like you're kind of under-booked on the proved side right now.

Well, we're under-booked in a sense that there is a 25% portion of the reserves of the project that are allocated to the probable category for conservancy – what’s the right word…to be conservative.

Phases 1 through 6. The basic flood.

In addition, our probable reserves, as I said, includes those other 4. So therefore our probable reserves are really more about, about 1/3 of our total Delhi instead of 1/4. But to the extent that the pricing changes the payout point, it will obviously have an impact because we start getting an extra 19% of the revenue or the rev reserves at that point. In addition, it will extend out the economic limit of the project, and that will also add reserves, but albeit at the tail end of the project.

Great. I appreciate all the color. It helps kind of dial us in a little bit, because it's hard to track sometimes.

I can assure you, it's complicated for us, and we have all the details and monthly production and so forth, so I sympathize.

Great. Just one more question, I'll jump off and let somebody else. On your other projects, particularly like the Giddings and some of your Eagleford and stuff, can you give us a little kind of your thought on the reason for JV partner? I mean, is it because of you just want to keep kind of capital on the balance sheet? Or I'm just trying to understand the economics of this projects, and at this oil price, why you wouldn't want to have more of them.

It's a real simple answer for you in the sense that these wells have very high rates of return. And if you look at it from that perspective, it's an extremely attractive investment. However, they're also very expensive wells. Our cheapest reentry is on the order of $1.5 million. Half of our locations are grassroot wells. We're looking at $2.5 million to $3 million apiece. For us, that is just too much money to spend on any one well in this -- on a risk return basis, it doesn't make a lot of sense to take that kind of risk with the amount of capital we have to work with. These wells also run off fairly quickly. We have a high initial decline rate. And so they're not the kind of wells that are suitable for a company our size to spend that much of our capital on. I’d have to go out and sell a bunch of stock and the stock is forever, but these wells are only going to contribute significantly for a couple of years. So the better thing to do for us is to bring in a partner on a de-risked basis. I mean if you’re looking after buying proved reserves and you have a capital budget of $100 million or $200 million. A $3 million well is not an issue. And so it's easy for them to participate with the expectation that they do enough of these wells, that they can probably rely on about 20%, 25%, 30% rate of return is extremely attractive for them, and that still allows us to capture probably up to half or more of that net present value in the project. Because we're getting a big chunk of it without spending the capital.

That makes sense. I was just curious like if -- do you have any lease issues or any reason that there's a sense of urgency to drill them that maybe it might be better just to wait until you have more cash flow from Delhi and then drill them then, or I mean does that go into the thought process?

That certainly is something we think about. There's no immediate lease issues that we have to get these drilled or whatever. To a certain extent on some of these as leases have gotten short on us, we just gone out and renewed the leases. It hasn't been an issue yet. We've never lost a location that we wanted to keep because of a lease term. That really is not an issue. It's just one of where is the best place to put our capital. We treat capital as being very expensive and precious and cash is the same way. So we want to be very careful where we put it. We don't want to put the company ever at risk, and we're not willing to dilute. Quite honestly, the other aspect, which is fairly unique to us, is Delhi. We believe that, that field, that asset, has a tremendous value that's only going to grow increasingly higher over the next few years relative to our stock price. And so we have that built-in dilution that we have to be very cognizant of. And that's why we're reluctant to issue stock at this price as we know that we're issuing it at a substantial discount to what we think the value's going to be in not that distant future.

That's great. I appreciate it. Thanks Guys, Keep up the good work.

Phil, I can confirm to you that the payout calculation uses the purchased oil price that we get from the first purchaser that flows through to our run checks, but that's also the way that it's calculated and...

Field level pricing then?

Pardon me?

That will be like considered the field level pricing is what you used?

And to answer your question how its audited the first purchaser has to report what he transports as well. So those things are audited along the way as the volumes. And as a matter of fact, David, my Controller, found a little price discrepancy one month and thought he found one, and inquired about it and turned out that, yes, there was a change in the contract and it hasn't quite caught up yet. So it did catch up, which they probably would have done on their own, but it's just -- we watch that stuff pretty closely.

[Operator Instructions] Our next question comes from the line of Joel Musante with C. K. Cooper & Company. Joel Musante - C. K. Cooper & Company, Inc.: I just have a couple of questions. I guess we'll start with your average rate. Currently, because in the second quarter you had some wells that were down that came back on, you brought some new wells on and then you had that other well that came on in April. So I guess if you were to look at it as a run rate at the beginning of April, whereabouts do you stand?

We’ll have to get that number. We tend to focus on a well-by-well basis, and I don't have the total, but the 2 new wells in Giddings, the Lightsey Wells, that's pretty much flat these days at about 350 MCF and about 15, 18 barrels a day. The size is limited by pipelines right now. We're a little disappointed that those pipes do not take as much as they said they were going to be able to take physically. They have one of them trying to work on a compressor, but the Dodd is making about 1.7 million a day on a regular basis, about 10 barrels of oil. A very high flowing pressure and a very small choke. All of our other wells are pretty much flat, the levels they've been at for pretty much the last 6 months. I can't tell you where Delhi is today. I mean, I know what it is in March, and I think I alluded to it in the release. Although we average 2,000 barrels a day, gross at Delhi, the rate actually increased steadily during the course of the quarter. And so our exit rate was well in excess of 2,000 barrels a day in Delhi. By prior arrangement, agreement, courtesy with Denbury, we don't give out monthly rate at Delhi, so we have -- we right now just talk about what happened in the prior quarter. Joel Musante - C. K. Cooper & Company, Inc.: All right. And you have, what, a 16% interest in those 2 wells, the Lightsey and the Dodd?

Yes. The Lightsey and the Dodd we have a 20% working interest and a 16% revenue interest in total payout, and then we'll go to a 38% and 30%. Joel Musante - C. K. Cooper & Company, Inc.: In terms of -- you talked about the out-performance at Delhi, and one aspect is the early response. I mean is it possible you can quantify or talk more about the -- how that -- in terms of production over-performance, how to characterize that?

Well, in terms of characterization, the best way is to say on Phase 1, we start injection in November of '09, and everyone believe that we wouldn't see oil response until the summer of 2010, and instead, we got it in mid-March, in half the time -- in less than half the time. Same thing with Phase 2. We start injection on literally the last few days of December, and we thought, again, it would be midyear at best, and instead, we had response within less than 3 months. So from that perspective, the reservoir, obviously, is performing better than expected. On Phase 1, I would think that most people would agree that Phase 1 has produced at a higher rate than was expected. You could do your linear calculations about all the phases or whatever, and it comes out to much higher peak rate than what's in the current model. Beyond that, I think it would be difficult for me to provide any more detailed characterizations of that improvement. It's a more qualitative assessment at this point in time. I do know that we're producing a rate right now, which is higher than what's in the forecast that was in our DeGolyer & MacNaughton report from last year. Joel Musante - C. K. Cooper & Company, Inc.: Okay. All right. That's helpful. And then, the contract that you guys are close to signing for the artificial lift technology. I know you haven't signed it, but, I mean, could you tell us what that might look like?

Well, it's a test process. We're going to demonstrate the technology in a couple of their wells. We'll pay for the cost of installing it. They provide the wells and fully equipped, and we have a sharing of the revenue from the installation. And it's a demonstration agreement and we're going to demonstrate it, and if it does what we say it's going to do then we're going to launch into discussions about how to expand that throughout their portfolio, which is quite considerable. Joel Musante - C. K. Cooper & Company, Inc.: Okay. So you're going to test it on one well or maybe 2 wells?

Couple of wells. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And what would be the test period before you decided to ramp up to something bigger.

Well, quite honestly, the test period is whatever it takes for the both of us to get comfortable with it, obviously, more they have to be comfortable than we are. And it's a, I want to say, kind of a touchy-feely. It's a kind of thing that you know it when you see it in terms of comfort level. Joel Musante - C. K. Cooper & Company, Inc.: All right. And then as far as Oklahoma, you talked about potentially ramping up a development program there in 2012. And I guess what's the timeline or what are the -- what's going to determine the timeline or what you do there?

We have our first test is this May or this month. I say first test. We’ve already reentered the well. We've already reperforated in the target zones, but the key is we have to frac it because it is a tight rock. And we'll probably want at least a couple months of production from that to get a sense of what we have and what rates and so forth. We have a second test that we're going to be doing later this summer in another part of the field. And then that will give us the additional data. Now it's not -- I mean just to be careful, that these are 2 tests that we're doing on our own wells, on our leasehold so that we know exactly what's being done, where it's being done, how it's being done and exactly what kind of data results, water, gas pressures and so forth. There are quite a few other wells in the area, in these formations, that have been drilled, completed, frac-ed and produced all the way through cumulative production, which are the basis for our optimism. But until you do it yourself, you know exactly what was done and how it was done, you can't say for sure that it's 100% comparable. So that's why you do your own test. But I would say that we ought to have sufficient information by this fall to move forward with a full-scale development, assuming the tests do what we think they're going to do. And that's actually a nice dovetail because, as Sterling indicated, we're generating substantial cash flow today, net cash flow, and that's going to continue to build, and so by this fall, we're going to have a fairly substantial amount of resources to work with. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And your initial development program would be sort of lease retention focused, I would imagine?

We have our acreage is in roughly about 30 sections in Haskell County area, which gross level is about 19,000 acres, although our net position is about 8,300, 8,400 acres, and so obviously, what you want to do is capture as much as you can through force pooling. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And what's spacing -- is it a standard 640 [acre] spacing unit?

Yes. But, obviously, we would expect the actual drainage is going to be a much smaller amount. Joel Musante - C. K. Cooper & Company, Inc.: Right. But -- and then -- but the gross number was, what, 19, you said...

About 19,000 gross acres. Now we can't -- we're not going to end up with all of that leased ourselves, because some of that is going to probably participate, and some of that acreages has already held by lease or by production and some of those folks will farm out to us and some will just participate. So our net position is going to be somewhere between 8,000 and 19,000. Joel Musante - C. K. Cooper & Company, Inc.: Okay. All right. That makes sense.

Joel, one answer to your question, on Delhi, we averaged about 190 BOE a day in March. To give you a comparison, we were about 240 in the beginning of the year. We lost the Pearson and some production decline we got down to 100, about 100 BOE a day, and now we’ve built back up to about close to 200. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And that's x Delhi?

I'm sorry, that's Giddings. That's approximately about what our Giddings production was. Joel Musante - C. K. Cooper & Company, Inc.: Right. It's about 200 barrels a day is what you said?

Yes. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And that includes the -- I forgot the name of the well. I know I’ve been hearing it from you -- the one that you brought out in April?

Dodd? Joel Musante - C. K. Cooper & Company, Inc.: Yes.

This is through March.

That would not include the Dodd because that came on first week of April. So the Dodd, you have to add on -- that would be -- you have to add on about 48 BOE a day net to us. Joel Musante - C. K. Cooper & Company, Inc.: Okay. And is the product mix similar to what you did in the-- I would imagine most of the, it got oilier or more liquid-oriented. So that probably -- the new wells that you brought on probably added a lot more liquids.

The Lightsey is making a fair amount of oil plus the gas that's being produced is extremely rich, and it is going to a processing plant, so we'll get a high amount of liquids out of that. We haven't gotten our first processing statements. I can't tell you exactly what the ratio is. In Dodd, I really don't have anything on that one yet because it just came online. We have yet to see the statement on it either. Now the Dodd, about 2/3 of that gas is going to a processing plant. It's not as rich a gas as the Lightsey, but it's still pretty rich, probably 1,200 Btu roughly, and 1/3 of the gas is going to a pipeline that does not have processing. So we’re selling it as Btu-rich gas. So there's no liquids there, and Dodd does make us some oil. That’s one of the downsides of being constrained and having to choke it way back is that we're not getting the oil rate out of it that we should have, that oil is staying in the well bore and the gas is just kind of percolating up through it until we can actually open that up and get the rate high enough to flush out the well bore. Joel Musante - C. K. Cooper & Company, Inc.: All right. Well, that's helpful, thanks a lot.

[Operator Instructions] And I show no further questions at this time. Management, please continue.

Thank you again, everyone, for participating. If you have any questions about what's been said today, we'll be more than happy to provide certification. If you were to give us a call, obviously, we won’t tell you any more what we've already said, but we'll certainly try to explain what we said better. Thanks for attending, and we look forward to talking to you again.

Ladies and gentlemen, that concludes our call for today. If you'd like to listen to a replay of today's conference, please dial (303) 590-3030, and enter the access code of 4436768. Thank you for your participation and you may now disconnect.