Evolution Petroleum Corporation (EPM) Q4 2013 Earnings Report, Transcript and Summary

Good morning, and welcome to the Evolution Petroleum Corporation Fiscal 2013 Earnings Release Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Sterling McDonald, CFO. Please go ahead, sir.

Thank you, operator, and good morning, everyone. Thank you for listening to Evolution Petroleum's conference call to discuss results for fiscal 2013 and the recent quarter ended June 30. My name is Sterling McDonald, and I am Chief Financial Officer of Evolution. And with me today are Bob Herlin, our CEO; and Daryl Mazzanti, our VP of Operations. Before we begin, let us cover the basics. If you'd like to be on the company's e-mail distribution list to receive future news releases, please see the contact information on our news release. If you wish to listen to a replay of today's call, it will be available shortly by going to the company's website at www.evolutionpetroleum.com or via recorded telephone replay. The necessary information can be found in the earnings release. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today may contain forward-looking statements that are based on management's beliefs and assumptions that are based on currently available information. We can give no assurance that such forward-looking statements will prove to be correct, as they are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. Our discussion also may include discussions of probable, possible or potential reserves or recovery. Such unproven estimates are more speculative than proven reserves. We'll begin with comments about our results for the year and quarter and then go to questions. Bob?

Thanks, Sterling, and good morning to everyone. Since the detailed numbers are readily available to everyone in the news release that was sent out last night, I'm going to focus my remarks on key overall results and operations. Sterling's going to provide some commentary on financial results, and then we'll take the questions. For the year, we had record earnings -- recurring earnings revenues and production. Earnings to common reached $6 million or $0.19 per diluted share, which is a 36% increase in earnings per share over last year. Revenues increased 19% to $21.3 million, and net production increased 9% to 621 barrels of oil equivalent per day net. All of these improvements are due to our core asset in the Delhi Field, and these record recurring levels of earnings revenues production are even more remarkable in that we had divested all of our non-GARP proved reserves and producing wells during the year, totaling some 2.3 million barrels of oil equivalent in reserves. Now our full year results were dragged down by the fourth quarter that declined in performance compared to the previous third quarter, and this for a number of reasons. Production declined 7% to 583 barrels a day during the quarter, primarily due to scheduled plant maintenance, infield drilling and the effects of remediating the release of fluids in June in Delhi. Revenues declined overall by 10% to $5.4 million due to lower production, but also due to a 6% lower Delhi oil price. These were partially offset by a 14% decrease in LOE. Our G&A offset some considerable nonrecurring charges that Sterling will discuss in more detail. And these are all temporary effects, however. Oil prices now are higher. Let's talk about operations. In Delhi, the remediation of the June fluids release by the operator is continuing. CO2 injection in the area immediately around the leak site was temporarily suspended while production was continued to reduce reservoir pressure on the leaking well or wells. Oil production at the area -- affected area declined correspondingly, and we expect that fuel production will be impacted through the first fiscal quarter and perhaps into the second quarter that ends December 31. Production averaged 7,180 barrels a day gross during the fourth quarter, so it has dropped below 6,000 barrels a day this summer before recovering somewhat. I would like to emphasize that the CO2 injection in oil production has continued in the rest of the field that has been developed to date. The operator stated that CO2 injection will resume in the area affected by the spill sometime by our second fiscal quarter that begins October 1, and oil production should respond accordingly. We also should begin benefiting from field response to the CapEx that was done in 2012. Our Delhi revenues have been impacted directly but temporarily by the this environmental event, and we have no reason to believe that our reserves and future production will be materially impacted. In other words, this is really not a material event to our overall value of Delhi. The impact of this event on the timing of reversion of work interest is uncertain, as the reduced oil production and remediation costs are being offset to some degree by lower cost of purchase CO2, higher oil prices that we're getting this summer and insurance reimbursement, plus the extent that this event may be covered by the operator's 2006 assumption of environmental liability and their indemnity of us. Due to this range of likely outcomes, our reserves report assumes a reversion date of January 1, 2014. In other areas, we continue to make steady progress in commercializing our GARP technology, with 2 recent installations that have been very successful. We acquired the Philip DL, a well previously banned as uneconomic by another operator, and installed GARP and got gross production up to about a 35 barrel of oil equivalent per day rate. Most recently, we installed GARP in a joint venture well, the Appelt G1, that's in the Giddings Field, and production has increased to an average of about 12 barrels a day so far this month. We hope to begin more extensive deployment during the second fiscal quarter. In Oklahoma, as we have previously announced, we're testing of our Mississippi Lime wells high-end zone after plugging back the lateral section. Prior to that, we sold down our participation in JV down to about a 34% level, and that saved us about $1.2 million. Further development has yet to be determined. We continue to work on monetizing our Lopez Field in order to redeploy the capital and staff to more productive areas. Well, we really believe in cutting our losses in projects that don't meet our economic criteria. Looking forward to 2014, our capital expenditure plan totals $18 million, $17 million of which is targeted on our 24% reversionary working interest at Delhi. And that represents an -- actually, an estimate of the full calendar year of 2014 expenditures. The balance of $1 million, plus up to $2 million of potential incremental expenditures, is targeted on GARP installations. Sterling will now provide some more background on the numbers.

Thanks, Bob. For the year, since production from Delhi was a much greater part of our total production, our blended production price increased 9% to $94 per BOE, even though we realized lower oil price in Delhi. LOE decreased 8%, primarily due to the Giddings sale. DD&A increased due to higher volumes and the addition of future capital expenditures at Delhi associated with the new expected recovery of NGLs there, offset by the elimination of future capital expenditures associated with the gassy proved reserves that we sold at Giddings. This yielded a $40 million expected net increase for all future development costs as compared to last year, but note that the increase in Delhi CapEx delivers a large increase in NGL reserves. For the quarter, earnings were adversely impacted by the plunging up of several nonrecurring expense items in fiscal Q4. These included legal and registration costs to amend our expiring shelf registration, litigation defense, expensing of transaction fees associated with the Giddings property divestments, the cost of the Delhi NGL engineering studies that increased our reserves there, and the application of a much higher tax rate for the full year that could not be determined until the Giddings divestments closed during the fourth quarter. Consequently, our earnings for the quarter were just under $1 million, and it was also due to lower oil prices sequentially that we received at Delhi. Of the -- as to liquidity and 2014, our working capital is up to $25 million, and we've maintained our current minimum unsecured bank revolver capacity. Our capital expenditures in Delhi are on the assumption of a 1/1/14 reversion date, obligating us to fund approximately $17 million in growth capital at Delhi in calendar 2014. We further expect to spend between $1 million and $3 million during the balance of fiscal '14 on GARP installations based on current negotiations and the potential for expanding that agreement. These expenditure levels are well within our current working capital resources, even before cash flow from operations generated during -- expected to be generated during fiscal '14, including any additions based on our MS Lime (sic) play, pending new test results. Since our shelf registration was due to expire this fall, we elected to renew and also to expand the capacity of the shelf to $500 million. While we have no current plans to utilize this capacity, it does provide us with considerable flexibility and multiple options going forward. In summary, we hit a speed bump caused by nonrecurring items during the quarter, as well as a temporary reduction of production at Delhi. And the current quarter nonrecurring expenses were -- excuse me, were in a large part due to the tax provision that we recorded in the fourth quarter. As an example, we had been recording -- had we recorded the fourth quarter at the same rate that we have recorded the prior 3 quarters, our tax expense would have been approximately $440,000 less, which would have improved our net income from what's been reported by 50%. We can discuss more about those details and how that occurred. But regardless, these items don't change our course, direction or underlying value per share. As to earnings, an upward step change will occur in our revenue and earnings when our working interest at Delhi occurs in the near term. In the intermediate term, our peak in Delhi production is not expected until 2016 or so. And as to underlying value per share, our reserve metrics continue to improve without the addition -- without the issuance of additional shares or debt. Our challenge, going forward, will be to redeploy and/or return to shareholders the massive free cash flows that lie ahead of us. Bob?

Thanks, Sterling. Looking forward, I think it's clear that we're increasing our focus on and our ability to begin delivering to shareholders the value that we've created to date. Simply increasing production revenues without increasing share value is just not a core strategy of this management. We prefer to limit our financial exposure to new projects until success is likely in them. And we won't have any problem with cutting those losses -- or cutting our losses early if a project doesn't meet our parameters of success. We are pleased that the company continues to be among industry leaders in key value metrics such as return in equity, return on assets and growth. The continued strong performance of Delhi during the year underscores the value of that asset and the increase in the near-term step change of cash flow expected, both with the reversion of our working interest but the resumption of oil production following the remediation work going on. With no debt, growing cash flow, cash on hand, and focus on our growth projects, we believe that we continue to be well positioned to perform on our overall strategy of delivering value to our shareholders. Now with that, we're ready to take questions. And operator, you can open up the line for those questions.

[Operator Instructions] And our first question today comes from Joel Musante of Euro Pacific Capital.

I just had a couple of questions. On the -- you said that the release didn't really impact your assets at Delhi. Can -- is it possible that you can quantify the impact to reserves and maybe PV-10 value?

Sure. One of the things that we did this summer was to go back to our reserves engineer and say, "Hey, this is what's going on. How does this change our reserves?" And this is -- we're not really sure when reversion is going to occur, because of all these other issues are out there, so we just kind of picked a date that was comfortably within the range of possibilities and had him go back and say, "Okay, is this going to change the reserves, is this going to change the value of the PV-10 and so forth?" And his resulting analysis was that no, it really didn't have any material impact on PV-10. It did affect the reserves slightly, but not materially, simply because, obviously, with -- if reversion is pushed back 1 month or 2 or so, then obviously, it's 1 month or 2 of production that we're not getting a working interest in. On the other hand, production for about a 6-month period of time at a gross level has been reduced. These barrels aren't going anywhere. They're just going to be recovered a little later along in line. So we'll still get our share of those. So materially, there has been no impact. Obviously, there is some near-term impact in that revenues and production are down a little bit right now. We prefer not that to be the case, but it's not like those barrels will disappear. They're just been pushed back.

Now, Joel, as to -- if you looked at -- if we would've reverted in September versus January, I think our net loss would've been about 140,000 barrels on a total quantity of 23 million so barrels of 3P reserve.

Keep in mind that, that is also -- that value has been offset by the fact that during this remediation period, they're buying a whole lot less CO2. So that has a big impact as well on the economics, because that CO2 purchase cost goes against our payout calculation. So that -- there is some offsetting grace there.

All right. Well, that helps. My next question is on, on the CapEx spending, how -- I mean, how is that going to be triggered? I mean, how are you going to -- is all in all going to be in the fourth quarter or -- because you're not going to know when it reverts until probably after it reverts. How does that get accounted for?

Well, obviously, we don't have any capital expenditure obligation until we have reverted. That's #1. Second thing is that, to the extent that we do have a capital expenditure obligation, it is being offset by the fact that with reversion, we're now collecting a much higher level of revenues. Instead of a 7.4% of their gross revenues, we're going to be getting 26.5% of the gross revenues. So it's a self-funding process. The assumption right now is that it's a 1/1/14 reversion date, which -- so we're exposed to all of calendar 2014 CapEx. Now that isn't a number that comes on January 1, and Denbury says, "Okay, you've reverted. And here is an invoice for a full year." It's something that's paid out over the course of the year. So it's spread out during the course of the year, so it's not all at once.

I think they have the opportunity to cash call us a month in advance for the subsequent month. So if your question is, can they call us for all of it? The answer is no. It's as spent, and the part about where we are relative to payoff, you are correct that we'll have to come to a month where payout occurs, and the next month, we're working interest on it. And it would be that month in which we'd incur our first capital expenditure or cash call, if you will, for that month. And maybe a following month at the same time. So there could be a little bunching, but not to any extreme.

All right. And then, as I try to model out the cash flows going forward, your LOE, when it does revert, is going to change, because you're going to include the lease operating cost from the -- from Delhi on those barrels for the reversion interest. So it's going to be front-end loaded with CO2. So I just wanted to get a sense for, maybe on a unit basis, what kind of LOE I should be using for that period. Because you're going to have some barrels that are not impacted. They're going to be the royalty barrels, and then you're also going to have the other barrels. So...

Well, it's -- the cap, the operating expense on a monthly basis fluctuates widely with the amount of CO2 being purchased, so that's, by far, the largest single component. I would say, just in general, gross operating expense has been running around $9 million to $10 million a month. For our share, that would be 1/4, a little less than 24% of that, on a monthly basis. Now remember, that's being -- we're paying for -- we're collecting far more than that in our revenue stream with reversion. I think the clearest sign that the field generates tremendous positive cash flow is the fact that the field has paid off the payout balance in a fairly rapid fashion. So obviously, it has to be able to generate substantial cash flow from operations for that to happen.

Joel, I think what you might do is -- Denbury shows their operating costs over all their projects, they come up to about $25 a barrel. And in that, they have, I believe, about several dollars, you'll have to look, of CO2 costs. And our cost -- I think they charge about, I don't know, $0.40 an Mcf to themselves, which, in comparison to us, if oil's $100, it's 1% of $100 is, plus $0.20, is going to be $1.20 an Mcf. So you can differentiate that and probably get into the ballpark, if that's what you're trying to do.

Okay, all right. I think that helps.

And you can use what Bob said, too, on the $9 million or $10 million a month. I mean, you might be able to come at it from that direction. So just kind of cross-check it.

Maybe -- it's not $9 million. It's maybe like around $10 million. You'd -- that'd be a better number on a gross OpEx on monthly basis. For our share, that would be 2 point -- $2.5 million, let's say, a month. On the other hand, we're also collecting 26.5% of the gross revenue, and we were at 7,500 barrels a day before the environmental event. So that would be the near-term rate. And then obviously, peak cash flow is going to be when the field hits its peak level of production of around 12,000 barrels a day.

Right, so LOE -- then most of that's fixed, right? So going forward, you can -- or, I guess there's probably some variable component with the CO2, but...

Well again, the LOE is tied heavily to CO2 purchase levels of -- I'm not sure that we're going to see CO2 purchases go a whole lot higher. I mean, we're -- I mean, it is front-end loaded, as you mentioned. So I don't know, we'll see. OpEx -- I don't see it going a whole lot higher than it is now.

Okay, all right. And just one more. On the G&A, I mean, is it pretty safe to say that we can use, just going forward, we can use the number that we had last quarter, I think it was $1.4 million?

Yes, well, there's a -- you can, but here's another bunching. Just be aware that we have always accrued bonuses at the rate at which we paid in the prior year. So what always happens in the fourth quarter is there's a true-up. We don't know until the end of the fourth quarter what that number's going to be -- or until, actually, after the quarter's closed. And so you've got to -- you have a little bit of a spike on that number there. I don't have it right at my fingertips, but I think it's fair to say that the G&A in the fourth quarter was plenty full because it had these NGL studies charged to it. It had transaction fees for the divestments that Giddings added to it that interestingly enough, we have to expense those divestment fees, that we can't put it in the net proceeds from the sale, and we don't recognize gain or loss on the sale, because the proceeds go into the full cost bowl. It's another one of those anomalies that the AICPA and the SEC kind of don't look at things like full cost accounting when they make some of these rules. So it gets plenty full, and you need to adjust your tax rate, too. Do not use -- basically, the fourth quarter is a full year -- I don't want to call it a true-up, but it basically is due to changing circumstances, and I can discuss the cause of that if you want to know the details of it, but...

The yearly rate was 38%. Should we use that for the rate going forward?

You can use it for the rate going forward, but actually, the fact of the matter, Joel, should be, all other things held constant, that we should go back toward the rates that we were using in the first 3 quarters of this year. What's happened is, as we have burned through our cost depletion and the NOL that, that may have associated, and you have to use it first before you get to percentage depletion, which is really our largest -- one of our largest tax shields in our company and at Delhi. And all of our models were showing that we had burned through all of our tax basis, and so we were going to percentage depletion and that's how we were computing our effective tax rate. Bear in mind that percentage depletion is a permanent tax rate difference because it's never recouped. We're actually taking, in essence, a phantom tax deduction of 15% of revenue, and it's never recouped anywhere. So it permanently changes your rate. But what happened in the fourth quarter was, is then when we sold the Giddings properties, that drew us back into reducing basis, and we didn't get to the depletion calculation for this year. Next year, we should, unless we had some sale event or something else that would intervene, but I don't see it. We should be going back to the first 3 quarters' rate, roughly.

That's not a small difference. It's more than [ph] a 5% difference in tax rate.

It is. That's correct.

So from 38% down to 33%. And the problem is, in the fourth quarter, we had to make up 3 quarters of that tax rate difference. And so the fourth quarter was hit pretty hard.

All right. And I know, what did you call it, the deferred amount is tough to estimate, but it's been running around 60%. Is that -- should that be the same, going forward?

It was deferred at 60%. I think that's going to...

Our expert.

It can change over time as our income goes up, I think. Because that deferred is brought about by timing differences with IDCs that are already set in place.

Yes, and what's going to happen, I think, is that we're going to lose the timing difference on depletion when we're in excess of basis. So I think our -- I think that our current portion will be higher, okay? Tax rate [indiscernible] better [indiscernible] is much higher.

All right. Well, that's the best we can give you at the moment.

What was the answer?

The current -- I'm sorry, the current portion would likely rise, even though our overall rates...

The 60% is not a -- the right number. It's higher or lower?

He said 60% is deferred, so 40% is current. And the current should go up, and the current -- and the deferred should go down, we think, in the future. Why don't you just -- I don't know, for lack of anything better, if I were doing it, based on what you just heard, I'd just cut it to 50-50 and call it good. I mean basically, we're talking about the cash flow difference -- the temporary change difference in cash flow that's going to be -- that's going to happen one way or the other, right? In a matter of time, okay?

All right.

Now let me modify that. If we start development drilling at Mississippi Lime or elsewhere, that will change that whole complexion, and our deferreds will stay high.

I mean obviously, our CapEx at Delhi will some have some component of IDCs to it, and so that will have some impact.

That's true, too.

I mean, this last year, we had very little CapEx. We only spent about $4 million total capital. This coming year, in 2014, we're looking at $18-plus million expenditure level. So we will have considerable IDCs in that.

Well, let me -- that would conflict with my comment about going to a lower rate. IDCs are a timing difference, and they don't affect the rate. But let me just say that the $17 million in capital at Delhi next year, the best we know, and we've modeled it out, has got a lot of leasing wellhead equipment in it, which is depreciable property and not depletable property. So bear in mind, we have 2 basic tax shields. One is the depreciation of our tangible equipment, and the other -- and through IDC or through depreciation. The other is not through IDC, but through depreciation of tangible equipment. And then we have our depletion allowance, which is affected by how much IDC we take. So...

It's a complicated issue.

It is.

And the next question will come from Mike Kelly of Global Hunter Securities.

I was just hoping we could go over that tax stuff again. That was fun.

I'm glad you think so.

I'll ask you some easier ones than that. Well, maybe easier. On the expected -- when do you guys expect a resolution on whether this -- the environmental liability will be picked up by insurance? And is that something you think that could be, really, kind of solved by the January 1 revision date?

The insurance issue is not ours. It is Denbury's. They have publicly stated that insurance is expected to pick up between 1/3 and 2/3 of the total cost. For our purposes of modeling, we assume a 50% reimbursement, just kind of picked a number in the middle of that. So the bigger issue, really, is when that reimbursement occurs, the sooner as of later, and how that impacts the payout calculation. And then the corollary to that is whether or not you -- that has even any application because, if our indemnity applies and if Denbury's assumption -- environmental liability applies, then it's a moot issue anyway. So there's a lot of these issues that are out there that we're in discussion with them on. And when that gets resolved, I couldn't tell you.

Okay, all right. Fair enough. And you guys are now reflecting a decent amount of NGLs in the reserves. It's good to see. I'm just hoping to get some color on when you'd expect to see the processing really up and running in the field here. What's kind of that build-out look like?

Okay, that is, again, at the moment, that's up to the operator, because we're not a working interest owner. Once we are working interest owner, then we'll have some input on that. In our reserve report, we've assumed that, that is not installed until 2016, so that would be the earliest you would see any benefit from that facility. It actually -- it basically added a third year of significant CapEx to the whole project. And how that processing gets done is still really open to question. We assumed a fairly simplistic model, where we're recovering the, initially, just the really heavy NGLs, which we call natural gasolines or the C5+s. There is some thought in terms of recovering the methanes as well, and that could be used as fuel for the plant to cut down quite a bit of LOE. There's also the issue of when or if we recover the C2s and through C4s because of the impact on the admissibility and the ability to compress the recycled gas. So these are all issues that we've already had some discussions with the operator about. And at the moment, they're the ones that call the shots because we don't have work interest ownership, and until we do, we don't have a whole lot of voice. Once we have a work interest position, then we have a whole lot more voice in the matter. But right now, it's a couple of years off.

Okay, understood. And what's that CapEx look like, maybe on the gross number ballpark, in year 3?

It's about...

$160 million -- $159 million, I think.

Is it 59?

Yes, million. That's for NGLs. It's not for the probable case, it's for the proved case.

Okay, the proved case. So the total 3P case, it's a $100 million gross number in 2016. So our share of that would be roughly $24 million. That's the 3P case, which is -- that'd be the gas, the natural gasolines, it's the methanes and the regular Y grade NGLs.

And I'll follow up on what Bob said, too, where he was talking about using the natural gas for LOE. It wasn't modeled that way, and the natural gas price is $3.25.

That's how it was valued...

I understand. I'm just saying is it's a $3.25 price tag.

Okay, all right. Final one for me. Sterling mentioned this, said the biggest challenge for you guys, really, determining how to redeploy cash flow going forward or give it back to shareholders. Just basically have asked just the last couple of conference calls, too. But any update here on which way you'd be leaning? And just some color on potential options there would be helpful here.

Well, this is kind of a sensitive topic, Mike, something that the board is reviewing and discussing with management in terms of what we're going to do, when we're going to do it and so forth. I think we've stated in the past that there's a wide range of options on the table that we're always looking at and have been looking at. And I think I've been really consistent over the last couple of years that we're open to any and all ideas to how to best get the value we've created into the hands of the shareholder. So that range of possibilities goes anywhere from paying a dividend to buying back stock to sale of the company. So we look at everything of this type on a regular basis. And I would say everything is always on the table until we pick a route. And even then, just because we go one route doesn't necessarily rule out another route.

Yes, it might be a combination. And some of it depends on our ability to deploy capital in a meaningful way conservatively in the ground, too. So -- but let me make one comment here. As far as -- we'd really -- the de-risking of this project has taken -- while we farmed out in 2006, and here we are, 7 years later, and a lot of de-risking has gone on, but there's still some pieces left. One of the big pieces for being able to lever the cash flows at Delhi is getting to our working interest because if you look at our royalty interest today, let's say that number's $20 million on an annual basis. When you look at some of the opportunities -- Bob said, well, maybe sale of the company. In that case, you have to look to the buyer and what their financial structure might look like and what do they need in order to support a price that we would be interested in. So let me give you an example. Let's say MLP ABC says -- looks at our $20 million of royalty cash flow and says, "Well, in order for that not to be dilutive to my unitholders, I can capitalize at 10%. So 10% times $20 million is $200 million. That's what we'll pay." Well, thank you very much, we're not selling it for $200 million. It doesn't mean that the value is not greater than $200 million. It means that the cash flow of that value is still in its infant stage, and it's about to take a step change. And when it does, our revenue's going to almost quadruple. And of course, yes, we're going to pick up some operating expense and some growth capital with that. But it's -- again, we're -- we've de-risked a whole lot, but we haven't quite de-risked that cash flow piece yet, not because it's questionable, necessarily. People don't question whether we're going to get it. It's just, if you look at -- somebody had to go to the bank and borrow, you have to look at, well, what's the borrowing base? And if you're allowed 3.5x, 4x EBITDA, you got to look at that. And then to that, let's say they add equity for a like amount, and you come up with a number that's short. We have to get value for our working interest in order for somebody to be able to lever these cash flows. But that'll come in due time, and not too long out in the future.

And the next question is from Brett Hendrickson of Nokomis Capital.

Sterling, I'm glad you explained that piece because I think it's a piece that's been lost on some people about the importance of the revisionary interest kicking in, but I had a little different question. But I wanted to make sure, Bob, did I hear -- did you say what the gross production is in Delhi currently? I'd be surprised if you did, but I almost thought I heard you say it in your prepared remarks.

If I did, it was purely an accident.

Improved.

Production has improved from the low point. Keep in mind that there was a lot of capital spent last year that, in the way that the field operates, you spent a lot of money, and it takes a while for it to respond, especially because you spend a lot of money in an area and you don't bring that area on until it's all done. And then you want to inject the CO2 for a while before you start even producing. So all the CapEx last year has yet to really be -- start being reflected. Well, now that it's September, we're starting to see, I think, some contribution from that work last year that's helping to offset the effects of the remediation work in that one small area of the field. So we're encouraged that it's doing better than it was earlier this summer. And how soon the spill area starts contributing getting back again in a significant way, that's going to be later this fall when -- not until injection begins again in that immediate area. And that's not going to happen for another month or so. They have to finish their work plugging out the second well, I believe it is, that may be a part of the leak, so -- yes, everything's moving forward, but if I gave you an actual number, it was my mistake because...

No, okay, I just wanted to make sure I didn't miss something. My phone cut out. But on that last part, you said about -- when they do start reinjecting in the area with the -- where the remediation is going on, is it going to -- it's not going to be like when you start from scratch 2, 3 years ago, but there -- is there going to be some kind of fill-up issue with the reservoir where you're not going to get as an immediate response to the reinjection, you might have to wait a period of days or weeks? Or how is that going to work out? I know we had to wait a while when the very first phase of the field, just because you were kind of stability from scratch before you got a response. What's the delay time, would you guess?

I'm not one to predict what Mother Nature's going to do out there, 3,000-foot deep. I would expect that you would have a lot faster response than when you started from scratch because, if you start from scratch, you have 2 things you got to do. One is, you've got to re-pressure -- add pressure to the reservoir. And then second, you've got to actually get the CO2 absorbed into the fluids in the reservoir itself. At this point, I would say that -- and this is pure conjecture, but it would be my estimation that all you have to do now is put some synergy back into that reservoir area because the oil has already been saturated with the CO2. So I would think that the response would not be as long as from the starting point. That's a purely qualitative answer. I couldn't begin to tell you, other than to say I think it's going to be faster than if we were starting from scratch.

Okay, understood. And -- so here's my real question, Bob, and it's a little bit hypothetical. But you mentioned the idea that you've been indemnified against environmental issues from when you did the farm-out in 2006. So hypothetically, let's say that after the fact, sometime after New Year, this might not be an easy agreement to come to, but the operator says, "You're right. You're indemnified. You're shielded from" -- I don't know, I'm taking a guess, making up a number, $40 million or $50 million of this $70 million cleanup. Then is it -- is there a potential then, at that point, then, the parties would have to agree that, "Okay, well then we have to go back and retroactively give you guys credit for some of these barrels that are produced." Because if it was originally supposed to kick in here this month of September, but not for this $70 million kind of push to the right, then if after the fact, you guys settled and realized that you weren't on the hook for all of those dollars, then they might be, like, say, on December 31, you guys might be talking, you might say, "Oh, really, we need to go back to October 15." And then would you retroactively get credit for that -- those barrels of production and that cash flow? Do you see what I'm saying?

That would certainly be our position. And obviously, I'm sure Denbury has a different perspective on this. And that's why, at time, we sit down and talk about these things and figure out what the best resolution is. But I can't argue with what you're saying. That certainly is the position that we would take.

Okay. And I don't want to get too under the covers here, but can I just ask you if those discussions have even started yet? Or is it too early to even have started those?

I think we're starting to very -- or move off into a direction that we really shouldn't be talking about.

That's fine, understood.

[Operator Instructions] And seeing no additional questions, I would like to turn the conference back over to management for any closing remarks.

Certainly. Thanks to everyone for participating. Feel free to call us if you want any more clarifications. We're certainly pleased with our overall progress for the year. Obviously, we're not pleased with the fourth quarter, but we think that is a temporary phenomenon that, certainly, by the end of this calendar year, we will be back strong again. So with that, thank you, and we'll talk to you next conference call.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.