Evolution Petroleum Corp (EPM) 2011 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Evolution Petroleum fourth-quarter and fiscal year-end 2011 earnings 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, Wednesday, September 7, 2011. I would now like to turn the conference over to Lisa Elliott with DRG&L. Please go ahead.

Thank you, operator, and good morning everyone. We appreciate you joining us for Evolution Petroleum's conference call to discuss results for the fourth quarter and year-end of fiscal 2011, which ended June 30. In a moment, I will turn the call over to management, but first I have a couple of items to cover. If you would like to be on the Company's e-mail distribution list to receive future news releases, please feel free to let us know. My contact information is on the earnings release that Evolution put out this morning, and 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 September 14, 2011. That dial-in number and passcode can be found in the earnings release.

Information recorded on the call today is valid only as of today, September 7 2011, and therefore time-sensitive information may no longer be accurate as of the date of any replay. And today, management is going to discuss certain topics that may contain forward-looking information, which is based on management's belief as well as assumptions made by management and information currently available to them. Forward-looking information includes statements regarding the expected future drilling results, production, expenses, reserves. And 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. And also, today's call may include discussions of probable or possible reserves, or use terms like volumes, reserve potential or recoverable reserves. And please note that these estimates are not proved reserves or resources, and are by their very nature more speculative than estimates of proved resources and reserves, and accordingly, are subject to substantially greater risk. Now with that, I'll turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob?

Thanks, Lisa. Good morning to everyone. Certainly appreciate you joining the call today. I'll briefly review reserves and operating results, and then update you on our future plans. Sterling, our CFO, is here today, and he will highlight some of our select financial information, and then we'll take your questions.

This morning, we put out a press release that reported our substantial increase in proved reserves, and our improved financial and operating results for the fourth quarter and year ended June 30. These results are primarily due to the success of the Delhi project which is continuing to perform well.

I'll start with the reserves first, as of June 30, 2011, the end of our fiscal year. Overall, we're very pleased to report that our proved reserves increased substantially, some 11.5%, to a total of 13.8 million barrels of oil equivalent, and that's obviously net of production during the year, sales in place, and any revisions. Our PV-10 increased by 41%, to a total of $375 million.

In particular, our proved developed reserves, almost all of which are producing, increased 378% to a total of 5.3 million barrels equivalent. Proved developed reserves now total 39% of our total proved category. Probable reserves, 94% of which is associated with Delhi, are a total of 6.2 million barrels equivalent, with a PV-10 of $76 million. I would also like to point out that about 30% of our probable reserves are actually in a developed producing category, and obviously that would be all at Delhi.

Let's talk about Delhi in particular. The improvements there are quite numerous. Over the last year, production response for the first 2 phases came on sooner than expected. Production grew more rapidly than expected, and the project has actually required less CO2 than projected.

We also benefited from higher oil prices, especially since the first of the calendar year 2011, due to the substantial premium that our Delhi oil receives compared to NYMEX WTI oil price. The oil we sell at Delhi is tied to Louisiana Light Sweet price, which tracks Brent, or imported oil, and that premium to WTI was more than $12 a barrel in the fourth fiscal quarter, or about 12%, and actually, that premium has increased through the near term. In fact, our most recent realized oil price at Delhi is substantially higher than the oil prices utilized in our SEC reserves report, and in our forward oil price curve evaluation.

As a result of these various factors, and the continued substantial investment during the past year by the operator, our independent reserve engineers calculated that the reversionary working interest payout has accelerated to calendar 2013 year end. That is more than 2 years earlier than projected in last year's report. At payout, our net revenue interest at Delhi increases from the current 7.4% to about 26.5%, and we would bear at that time a 24% working interest share of operating cost and future capital expenditures.

Due to the accelerated payout date, we're now projected to actually bear our 24% share of capital expenditures, beginning in 2014, which will include the last phase of the proved reserves development, but our share of capital expenditures will still be far less than our net operating cash flow from Delhi that same year. These factors also had a big impact on the discounted present value of our proved reserves at Delhi or PV-10, which increased to about $334 million. From a volume standpoint, we reported an increase of 16% in our proved reserves to 10.9 million barrels at Delhi, and that's all 100% oil.

It's particularly important to note that due to the improved field performance and the ongoing investment by the operator, our proved developed reserves at Delhi increased to 4.9 million barrels, or about 45% of the total proved there, with a PV-10 of $192 million. Probable reserves declined about 19% to 5.8 million barrels, but this is due to the upgraded reserves to the proved category, but our probable PV-10 still increased 42% over last year, to a total of $73 million.

Of our probable reserves, about 1.9 million barrels are in the developed producing category. As a further note, the 5-year forward oil price evaluation for Delhi -- which is still at a lower oil price than our most recently realized price -- increased our proved and probable reserves to 11.2 million barrels and 5.8 million barrels respectively, and the PV-10 to $418 million, and $95 million respectively, or well over $500 million for the 2 combined.

Moving on to Giddings, during 2011, we drilled 3 horizontal development wells in the field through a joint venture. While our results were mixed with 1 excellent well, 1 mediocre well, and 1 poor well, the excellent results in our Dodd #1, which we previously announced, may well end up offsetting the other 2 wells drilled, which is actually a common event in that field. We still have 13 proved development locations there, 2 of which are held by production, and 3 of which offset the 2 best wells that we've drilled in the entire Giddings Field to date. Proved reserves at year-end in Giddings totaled 2.7 million BOE, with PV-10 of $41 million. In the 5-year forward curve evaluation, that PV-10 increases to about $52 million. Our production during the fourth quarter averaged 209 net BOE a day.

Moving south to our Lopez Field in South Texas, we continued testing of 1 producing well during the year. We're very pleased to achieve increasing oil production that first began a year ago last summer. We recently confirmed the potential in the field by installing a larger submersible pump that produced 50% more fluid and 50% more oil. You might remember that we had downgraded those proved reserves a year ago due to our limited saltwater disposal capacity, and at that time, uncertain and limited test results. Due to the improved results during the year, and expanded and extended testing, we have been able to restore those reserves to the proved category and again view this field in concept of having considerable potential for the Company going forward.

Our independent reservoir engineer assigned 61,000 barrels of proved oil reserves to the 1 producing well in 5 drilling locations and 378,000 barrels of probable reserves to 36 drilling locations. Again, this is 100% oil. Associated PV-10 is about $0.5 million for the proved reserves and a little over $3 million for the probable. These reserves are calculated for a low total flow rate well, whereas our plan going forward is to drill wells designed for a very high flow rate and, therefore, better economics per well. The 5-year forward curve evaluation increased proved and probable PV-10 to about $1 million and $6 million respectively.

Moving to the north, in Oklahoma, we conducted our first test operations in Haskell County this year, by re-entering the well and deepening it to allow salt water disposal in the same well bore in which we plan to produce gas. The targeted saltwater disposal formation, however, produced gas when we perforated it. Therefore, we changed our program on the run to adequately test this new target, and after a delay in getting the frac date, we were able to do a single stage frac in this vertical well bore, and are now producing gas to sales, while we're dewatering the formation.

As a result of this work, our independent reservoir engineer assigned a modest amount of proved reserves to this formation, over a limited portion of our leasehold. We expect to resume testing the Woodford Shale in Haskell during fiscal 2012, and we believe that development is attractive, even at the low current natural gas price. Now, we have deemphasized our Wagoner County leasehold due to mixed results to date, the need for added infrastructure, and the low gas price in place, and we consequently expect to divest that asset.

Overall operating results we're very pleased with. Our growing oil production, combined with higher oil prices allowed us to generate net income of about $0.5 million or $0.02 a share, fully diluted, on revenues of about $3.2 million, just during the fourth quarter. Net sales volumes for the Company in total increased to 438 barrels of oil equivalent per day, which is up 30% over the volumes in our third quarter.

Now, a 48% increase in Delhi production from the third to the fourth quarter average rate of almost 3,000 barrels gross production per day in the field was primarily due to increasing contributions from Phase II, and this growth should continue into the 2012 fiscal year. The operator is currently installing Phase III during the calendar year, and we expect to see oil production from Phase III next year. For the year, we grew revenues by 50% over 2010, to $7.5 million, and we approached the breakeven point with a narrow loss of about $200,000.

Looking forward for fiscal 2012, our capital budget is very flexible at this date. [Vying] for a base level of expenditures and activity with potential expansion to 12 million or more, depending on results of the initial drilling in South Texas, subject to initiation of joint ventures that are currently in discussions or negotiations for development drilling in Oklahoma and in Texas, and other opportunities that may arise during the year.

Our base case and expanding case of capital expenditures will be funded from existing working capital, and particularly cash flows from operations. Other supplemental fundings for us as needed, could include divestments of non-core assets, further joint ventures, project financing, and net proceeds from future sales of our 8.5% non-convertible preferred stock. Additionally, we may choose to establish a bank credit line to provide additional liquidity.

The Delhi operators continue to fund installation of Phase III of the EUR project in Delhi and we don't plan or expect to have any capital expenditures there until fiscal 2014, the latter half of that year.

Our initial focus in Giddings will be to drill 2 offsets to our 2 best wells in Grimes County, most likely with 1 or more partners. Additional activity likely will be through 1 or more joint ventures.

Separately, we're in the early stages of a new project that we believe will be 90% or more oil, and composed of proved and probable drilling locations in an extended area of the Giddings Field, but any leasing or drilling in this project will be through a joint venture.

In Oklahoma, we expect to begin development of the Woodford Shale in Haskell County, horizontal drilling. At this time, we're not really free to discuss the details of that activity.

In Lopez Field in South Texas, we're planning to reinitiate development operations with the drilling of a minimum of 4 wells by the end of calendar 2012. The results of those wells will drive our expansion plans there during the remainder of the fiscal year.

Earlier this summer, we announced the receipt of formal notice that the Patent Office intends to issue a patent on our artificial lift technology, that we have trademarked as GARP, standing for Gas-Assisted Rod Pump. We should receive that formal patent in our hands shortly. This is a big, important milestone, because it allows us to be more aggressive in pursuing agreements for demonstration and deployment of technology, without concern for contractually protecting our intellectual property rights.

We believe this technology can be useful in adding economic reserves to a portion of the rapidly-increasing number of horizontal wells worldwide. We expect to install in at least 2 commercial demonstrations this fiscal year. We expect to continue testing, and begin commercial demonstration of GARP shortly. And with that, I'm going to turn it over to Sterling, let him talk about some of the numbers.

Thanks, Bob. Good morning, everyone. Let me just walk you through a few key highlights. Gosh, it's hard not to be excited about our financial performance and trends that are developing. Financially, there's a lot of good things happening.

In addition to Bob's terrific report on our reserves and PV metrics, we turned the corner on net income. As Bob mentioned, net income exceeded $500,000 in the last fiscal quarter, a sequential improvement from the net income of $170,000 in the prior fiscal quarter, and $1 million positive swing from the year-ago's greater than $400,000 net loss. Year-over-year, annual net losses improved 90% or $2.2 million from a $2.4 million loss in fiscal 2010, to a $240,000 loss in fiscal 2011. Similarly, cash flow from operations before changes in operating assets and liabilities increased 102% year-over-year, from just under $900,000 in fiscal 2010, to $1.8 million in adjusted cash flow in fiscal 2011.

So here's what's happening here. We have a unique operating leverage that's kicking in, and that leverage is due to our growing royalty interest at Delhi that carries no operating expense. As an example, revenue in the fourth quarter was 57% sequentially higher than in the third fiscal quarter, while operating expense only increased 7% in that same period. This trend is expected to continue over the next couple of years, as Delhi production ramps up prior to our payout, without a concurrent increase in expenses there.

Looking at the top line, despite a 7% decline in year-over-year sales volumes, our annual revenues increased 50% to $7.5 million in the current fiscal year, compared to $5 million in the prior fiscal year, primarily due to a 95% increase in oil sales volumes and higher oil prices. Quarterly sales volumes also steadily improved during most of the current fiscal year, with the last quarter averaging 483 barrels of oil equivalent a day, up 58% from the fiscal first quarter's 270 BOE a day.

Here's an interesting milestone. We're just shy of our singularly highest production quarter ever, of 474 BOE a day during the quarter ended 3/31/2009. On the expense side, we have held the line on G&A costs, both quarterly and year-over-year, excluding legal expenses to protect our property rights. Our depletion rate rose slightly in Q4 this year, to $4.92 a BOE, compared to $4.55 per BOE average for the entire fiscal year. Although that's still a very competitive rate, the increase is due to $12 million of additional capital expenditures Bob spoke about that are associated with the development of the final phase of Delhi after our accelerated reversion date is expected to occur. In this case, that's a good thing. We picked up an additional 1.5 million barrels of proved oil reserves for an $8 per barrel investment.

As Bob mentioned, we're fortunate that Delhi's LLS or Louisiana Light Sweet Crude pricing has remained coupled to Brent pricing, unlike WTI that's decoupled downward to Brent. LLS may remain advantaged to WTI, as unlike in the US, world market demand is still strong against tight supplies.

Concerning our strong financial position, at June 30, 2011, our working capital was $4.1 million, compared to $4.9 million at June 30. We continue to be debt-free.

On July 1, after the current year's close, we sold 220,000 shares of our currently authorized 400,000 shares of 8.5% Series A preferred stock with a liquidation value of $25 per share. Gross proceeds from this tranche were $5.1 million before offering expenses. These shares are perpetual, non-convertible, redeemable only by the Company at par after 3 years, or earlier at a small premium in the event of a change of control. We have since been able to sell a portion of the remaining 180,000 authorized shares, all at a premium to their $25 per share liquidation value.

So as you can see, it's been our intent to build cash and financing resources for future opportunistic capital deployment in the form of investments in our projects, investments in others' projects who are over-commited, or investments in our common stock. Our financing quiver now includes, for starters, our June 30 working capital and July 1 sales of preferred stock that allows us to fund our base 2012 capital budget out of existing cash on hand, right now, today, with liquidity to spare. Second, absent plunging oil prices or field upsets, our positive and growing cash flow from operations should easily cover an expansion from our base plan.

Third, our preferred share platform is registered on the shelf, authorized and ready to go with further sales as necessary, markets and investment needs permitting. Fourth, we're also working to establish a small $5 million unsecured bank line, only to be used as bridge financing, if necessary. Fifth, we may divest of certain of our non-core assets for capital redeployment. Sixth, our common stock is a currency as well, if and when markets allow fair value. And lastly, we continue to eschew debt, unless it's contained to a individual project or asset. So these are the kinds of options I'm privileged to have and stand behind as CFO of the Company.

Before we go to Bob's closing remarks and the Q&A, I'd like to address some questions we received from our shareholders. This may be old hat to many of you, so I'll try to be brief.

We chose the preferred platform for several reasons, but mainly for principles we hold firmly to, that of maintaining control of our assets, to ultimately achieve underlying fair value for our common shareholders. Unlike debt, the preferred acts like and is booked like equity, because it doesn't have a due date, it can't be called by the holder, nor can our assets be foreclosed upon for non-payment of dividends. We also saw that it was available at somewhat reasonable price, about the same as a subordinated debt, without tax benefits.

Granted, a convertible feature would have lowered the dividend rate, but we intentionally did not dilute our shareholders with additional or potential issuances of our common stock, nor do we believe that the reduced coupon is fair consideration for the additional shares we would have had to issue.

By the way, this also benefits Bob and me as the largest and second largest inside beneficial owners of our stock. I think that's how that stock option grant thing is supposed to work, and it's working on me.

On the preferred stock sale, management was not subject to insider trading rules in their purchases of preferred, at its IPO. This is because shares were sold by the Company, which is all-knowing, as opposed to any disadvantaged unknowing public shareholder selling the shares to us. Personally, I was hopeful that management's participation would be viewed as a positive additional commitment to our shareholders, as if I need more concentration risk, I really don't, but I bought some of the shares and put them away.

Which leads me to insider sales of our common stock. We've been asked about insider sales, and to my knowledge, no named executive officer has sold any common stock, except to cover tax liabilities upon vesting. In my case, I've sold none, thereby requiring me to write a quarterly check for taxes upon vesting, and a tax withholding check for each of the last 2 years' bonuses that were paid, not in cash, but in stock. That's an interesting concept, Bob and I came out of pocket from our salaries to pay for our bonus.

On another financing note, oil and gas revolvers don't go for 2% or 3% these days. It's true that very slim margins are routinely committed by banks against an almost 0% LIBOR rate, but most lines have a floor rate, and currently that would be about 5% for us. Regarding our royalty interest at Delhi, it doesn't back in. We own the royalty interest now, and for the life of the project. Rather, our working interest backs in, adding a 19.1% revenue interest to our current 7.4% royalty revenue interest, while also obligating us to begin bearing 24% of the cost expended after back-in reversion.

Regarding production or sales volumes, E&P companies quote net production or sales to their specific interests, unless otherwise noted. This is the case with Denbury. They quote their net production from Delhi, which is currently about 76% of total field production. So Evolution's current interest is not 7.4% of Denbury's net interest, rather, it is 7.4% of Denbury's net interest divided by about 0.76. That also equates to 7.4% of total field production, which is currently what we own. In our reports to you, we try to quote both field gross production and net production to our interest at Delhi. Lastly, our South Texas oil project in the Lopez Field is not planned for horizontal drilling development.

In conclusion, I sleep well at night as your CFO and a major shareholder, knowing we have a great set of assets and significant liquidity and capital resources at our disposal, even if capital or oil markets turn temporarily ugly again. On this latter point, our collective experience makes us not prone to bet our survival on any specific financing, asset sale, 100% field utilization, or for gosh sakes, stable oil and gas prices. Ignoring those risks is just not our style.

Without naming names, there are a number of public oil and gas startups that are no longer with us. Of the remaining E&Ps, in the small cap space, which we consider to be under $640 million, over half have given shareholders negative returns over the last 5 years, compared to the highest upper quartile performance we've provided to our shareholders of about 19%-plus compound return over those 5 years. We've also supplied the highest quartile performance over the most recent 1 and 2 years. So speaking of our stock price, Bob, will you tell us more about the valuation parameters that underlie our value?

Thanks, Sterling. I'd like to reiterate how pleased we are with how well things are going for the Company, particularly in Delhi field. These are exciting developments that add considerable value to our Company. Just to better illustrate that value, each fully diluted common share of our stock represents about 0.4 BOE of proved reserves and about 0.2 BOE of probable reserves, with a proved PV-10 of more than $11 per share, and a probable PV-10 of more than $2 per share. In fact, our proved producing PV-10 alone is about $6 per fully-diluted share which was about our current market price as of the close yesterday, and we are still realizing in Delhi an oil price that is greater than that used in our reserves report.

Buying our common stock today is equivalent to buying proved reserves that are 84% black oil, 39% developed producing, at a cost of about $13 per BOE with less than $3 of future capital expenditures in limited operating expenses and severance taxes. If you include our probable reserves, which are primarily at Delhi, the equivalent cost of BOE drops to a little over $9, with about $3 of future CapEx and again, limited operating expense and severance tax. With that, we're ready to take questions. Operator, please open the lines.

Thank you, sir. We'll now begin the question-and-answer session. (Operator Instructions).

Operator, while we're waiting for anyone in the queue, I meant to mention something about our pricing. For the year, our blended pricing has increased substantially. But as an example, for the 3 months ended 2011 and the 3 months ended 2010 -- the 3 months ended 2011, our blended prices were $79.50 per BOE, compared to $44.50 per BOE in the prior year 3-month period. The point here is that our crude oil averaged in the last quarter $113.25. Obviously, the lesser-valued products, such as natural gas, and to a lesser extent, NGLs, pulls that average down and the point -- another point I want to make here is that the reserve report at Delhi, as required by the SEC, requires us to take the last 12 months, beginning of the month pricing, and do an unweighted average of those prices, and apply it to our forward cash flows and reserve reports. That price at Delhi was about $94 and change.

$94.81.

$94.81. That compares to the blended oil price we've received over all properties of $113.25 in the last 3 months, and within that, we have some oil products at Giddings, which brings the average down. I'm looking right now at Bloomberg, the price for Louisiana Light Sweet today is $115 and change, a barrel. So we have in the report, something a little under $95 a barrel, flat going forward, to produce the PV-10s on an SEC pricing scheme that Bob discussed. But the price that we're receiving is much closer to LLS trading at $115 today.

Questions?

Our first question is from the line of Joel Musante with CK Cooper & Company. Please go ahead.

Hey, Bob, hey Sterling, how you doing?

Hey, Joel.

Pretty impressive reserve growth, especially on the proved developed side. I just had a question about it. Given that it grew so fast, I mean, what phases of the Delhi development does that include?

That includes probably close to full response from Phase I. It would include a partial response from Phase II.

Okay.

You might recall, Phase I started production in March of 2010, and didn't start peaking or getting close to peak until a year later. So there's every reason to believe that Phase II is probably going to have somewhat of a similar incline and I think that we're seeing that in more recent production numbers.

Okay.

We have the rest of Phase II to see response from and then we have, obviously, Phase III which is going to be installed this year and then still have Phases IV and V after that.

Phase I from what I recall was about half the -- I'm not sure half in the size of reserves but that's kind of what I thought. (multiple speakers) Oh, just number of wells. It doesn't mean reserves necessarily.

Well, it's -- the patterns are probably --

Similar. But the reservoir may not be.

Each well is going to have the same kind of spacing.

Okay. It's probable -- it's gone off an analog, so it's probably pretty consistent across the field, on an average basis or --? All right. And then --

Phase I was up to over 2,000 barrels a day. The last numbers we had, which were back in March, I think, it was a breakout between the 2 phases. So I'm -- if you assume that is the peak with Phase I, which I don't know is the case, it may be or may not be, but if it is then you would say the increase over that would be the start of Phase II.

How much reserves were associated with Phase I and Phase II?

We don't have those numbers. The PDP is associated with Phases I and II.

Okay. But it's not the whole thing.

I would suspect the proved developed does probably represent all of Phases I and II.

All right.

That are proved.

As your question as to reserve growth, Joel, on proved reserves, again that is over all phases, mostly related to the earlier back-in.

I'd also like to point out that the way the engineer did the reserves is, took a number, a recovery number and he took that into 2 pieces. He has a 13% recovery rate for proved and another 4% for probable and he applies that to every pattern whether it's developed, producing or not. That's why we're reporting that we have what we call probable developed producing. That's that additional 4% recovery that's associated with Phases I and II that have been developed, all the money invested, and they're now in the producing status.

Okay. And the reason why your PV-10 grew so much was probably -- or a big factor of why it grew so much, was probably because you accelerated the reversion date?

Yes, that's a big part of it. The other big part is that the amount of purchased CO2 is substantially less than was originally projected, which is a big cost driver, because that is an operating expense to the project. So that comes out of cash flow with a working interest, and it comes out of cash flow and the calculation of our payout. Obviously it doesn't impact us on our overriding royalty interest, because we don't have any expenses associated with that. But the CO2 content really was the biggest single driver, followed secondly by the improved performance of the production side, followed by oil price.

Okay. All right. And -- go ahead.

You might flip 2 and 3. Actually probably oil price is ahead of improved performance.

Okay. All right. And then just could you go over how the accelerated -- I mean, I didn't look at that as a potential scenario. I was just trying to come up with a model to evaluate in. How did the accelerated reversionary interest work?

The way that works is there's 2 different ways you can do payouts. You can do an actual payout which is, whenever the operator recovers 100% of its capital expenditures that they actually spend, then that would be an actual payout and therefore the payout's going to fluctuate, not just with oil price and production but it's also going to fluctuate with how much money they spend on capital. At the very beginning when we negotiated this deal, back in 2006, we really didn't want to be exposed to that.

So what we agreed with, with the operator, was that we would just come up with a number that we jointly agreed was a fair estimate of what the CapEx is going to be to install the project and then whatever -- we call that our Dean payout. Whenever the operator hits 100% -- from 100% of the working interest, gets revenues less operating expenses equal to that Dean number, which is $200 million, then that's when our payout occurs. So we're totally indifferent to how much money they spend in capital out there. Except to the extent obviously, the more they spend, perhaps the faster it gets done. But anyway, that's why we call it a Dean payout, and we're actually have been starting to whittle that number down now over the last 6 months or so.

Well, nice job. That's all I had.

Thanks, Joel.

Thank you. Our next question is from the line of Mark Aydin with MLV. Please go ahead.

Good morning, gentlemen. Congratulations on the quarter.

Hey, Mark. Thanks.

I just had a quick question in regards to Phase III. I know you said it's in the process of being installed. Is there a time frame when we would see, or when you expect to see first response from Phase III?

Well, it probably is going to follow the same schedule as the last 2, where you spend the year installing it, you start injections towards the end of the calendar year, and then you expect response from it anywhere from 3 to 6 months after you start injection. So Phase III production is probably going to be sometime in 2012, anywhere from the beginning of the second quarter to the summer. Hate to say it's going to be accelerated response like Phases I and II are. We hope so, but we don't want to count on it.

That was going to be my next question. I know Phase I and Phase II had the early response, so I was going to ask if you expected Phase III -- but I'm sure it's too early to tell, so --

Phase III is going to do what it's going to do. A lot of it depends on -- as you start installing these phases, what you're doing is extending off an existing set of patterns, and so you don't really know how much CO2 has leaked off to the new patterns and how much CO2 you're going to have to put in to get filled up and to move your oil banks to the new producers. It gets very complex and the more -- the further along you get, the more complex it gets.

Okay. Well, thank you again, and congratulations again.

Thanks, Mark.

Thank you. (Operator Instructions). Our next question is from the line of [Robert Miller], Private Investor. Please go ahead.

Hey, Bob.

Good morning, Bob. Good morning, Sterling.

Hey.

How you doing this morning? Everything looks great.

Thanks.

I have a question -- a couple questions on Delhi. Denbury in their 2010 10-K state -- early performance data is indicating that Delhi field is acting as a miscible flood, instead of a near-miscible flood as we had originally modeled. If this is true, and if it continues, should positively affect our results. Could you give me a little more color on that, and exactly what the ramifications are of that?

Sure. When you're doing CO2 floods, you have 2 basic types, you have miscible and an immiscible. The miscible flood is where the CO2 is being injected at a sufficient depth, where the pressure of the reservoir can be maintained at a level that causes the CO2 to be fully absorbed within the oil, and therefore, you get a lot of positive things going for you. You're actually changing the characteristics of the oil itself -- viscosity, tension, surface tension. All kinds of neat things that can go on, as well as adding pressure to the reservoir, and you get your highest level of recovery in that event.

And immiscible flood is where you're too shallow to allow the reservoir to get to that pressure. You try to pressure up too much, then you end up really fracturing the reservoir, then you start having problems where the CO2 starts leaking off, which is not good. And as a result, then the benefits of the CO2 are limited. You don't get quite a good an impact.

Obviously, what we're describing is 2 ends of the extreme. In real life, it's somewhere in the middle, and the question is, where are you in that range, between the 2 extremes. Going into this project, the original thought was that this would likely be somewhat, as they called it, a near-miscible, like a near miss in airplane terms, I guess. I never did understand that concept, though, either you miss or you don't. Anyway, in a near-miscible, what you're doing is you're getting some miscibility and some immiscible factors, depending on where you are in the reservoir, and so you get some benefits.

That's originally where we thought we were with Delhi and what Denbury's stating is that the indications are that this perhaps might tend closer to the end of the range of a miscible, which would lend itself to saying that we're going to get much higher recovery -- not much higher -- we get a higher level of recovery. Clearly, the accelerated production response, the higher production rates, all are what I'm assuming they're referring to in terms of performance lending them to thinking this is more miscible than previously thought. Does that help?

That helps a lot. That sounds great.

Sounds like I know what I'm talking about, doesn't it?

I have 1 more question. You have said in the past that there's a chance that the OOIP could increase by about 15%. Does that involve tapping the 4 additional reserves talked about in the 2010 reserve report? And if yes, do you know what the past, primary and secondary production has been from these reservoirs?

Sure. OOIP stands for original-oil-in-place.

Yes.

Which is the amount of oil that was there before the very first well was drilled to it. And that is a number that's an estimate that is based on well data, taking estimates from the 400-or-so-odd wells that were drilled, the logs, taking estimates of the porosity and the original oil and water saturations and recovery estimates and so forth. That is a number that is a lot more precise than it is accurate, because you're just taking a snapshot of oil, of the reservoir parameters, in just a few spots in an area covering some 13,000 acres or 21 square miles, and so your actual reservoir can be substantially different than what you might otherwise estimate.

The original projected oil-in-place in the flooded zones of the original project size or scope was about 350 some-odd million barrels original in place, of which about maybe 190 million or so, maybe less than that, have actually been produced to date in the primary phase, which is just sticking a well in the ground and letting it produce on its own, maybe putting in pumps as artificial lift and then that also includes the secondary recovery, but in this case it was kind of a version of a secondary. It's what we call pressure maintenance. A true secondary operation is where you have a flood pattern, where you have 1 producing well surrounded by at least 4 injection wells, so you get real high sweep efficiency and, therefore, a lot of contact between the water and the oil.

At Delhi, that was not the case. What we had was a pressure maintenance project where they took produced water and injected back in the reservoir on the down dip side, just to maintain overall pressure, but not to try and have a high sweep efficiency. Therefore, there is a reasonable belief that we may actually have some secondary recovery oil in the reservoir to be recovered. That is 1 possible explanation for the improved performance to date. There's also been some work done in the field, through seismic and so forth which suggests that the reservoir could be bigger than originally thought, in which case the original-oil-in-place may be higher. Obviously, a 17% recovery of 450 million barrels or 400 million barrels is a lot better than 17% of 350 million barrels.

Those numbers do not include the 4 additional reservoirs that we've cited that are in our reserve report, but it's strictly and totally in a probable category. Those add about 8 million barrels of gross oil recovery to the project, but it's more towards the tail end. Those are probable reserves at this point because we don't anticipate that development work will actually occur until later this decade, which is beyond the 5-year window requirement that the SPE have for defining proved reserves.

Under those rules, you can't include as proved anything that you're not going to develop in the next 5 years and so we're just right past that window for these last 4. So those are going to stick in the probable category for a while. Kind of a long-winded, rambling answer. Did I answer it?

Yes, that's very good. That really sounds like that 17%, with what you're talking about from the secondary recovery, that 17% is probably low.

We certainly hope so. I think there's every reason to believe that it's going to be better than that, but that's something that's going to be subject to performance. Hopefully performance in the field over the next year will allow the engineer to maybe start including some of those as proved. Or actually going from 13% to 17% proved, maybe taking something beyond 17% for the probable. That's a year from now.

Okay. Well, that answers my question very well. Thank you very much.

You bet.

Thank you, Bob.

Thank you. I'm showing no further questions. I would like to turn the call back to Mr. Herlin for closing remarks.

Thank you. Again like to reiterate that we're extremely pleased with the results of this year. We're very pleased that we're going to be joining or have joined the ranks of companies with earnings for the last 2 quarters, and going forward that should be the case, absent some extreme upheaval, obviously, in the oil price. But we're very pleased, and we're excited about going forward, and we think we're going to be very active going forward in these various projects and feel free to call us with any questions about the remarks we made today. Thank you and good morning.

Ladies and gentlemen, that does conclude our conference for today. If you would like to listen to a replay of today's conference please dial 303-590-3030 followed by the access code of 4470734, and the pound sign. Thank you for your participation. You may now disconnect.