Evolution Petroleum Corp (EPM) 2011 Q2 法說會逐字稿

Thank you for standing by. Welcome to the Evolution second quarter of fiscal 2011 earnings conference call.

During today's presentation all parties will be in a listen-only mode. Following the presentation the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Thursday, February 10, 2011.

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

Thank you, Brandi, and good morning, everyone. We appreciate you joining us for Evolution Petroleum's conference call to discuss results for the second quarter of fiscal 2011 which ended December 31.

In a moment I will turn the call over to management, but first I do have the regular items to go through. If you would like to be on the Company's e-mail distribution list to receive future news releases, please feel free to let me know. My contact information is in the earnings release 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 February 17, 2011. That dial-in number and pass code can also be found in the earnings release. Information recorded on the call today is valid only as of today, February 10, 2011, and therefore time-sensitive information may no longer be accurate as of the date of any replay.

Today management is going to discuss certain topics that may contain forward-looking information, which are based on managements' 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 discussions of probable or possible reserves or use terms like volumes, reserve potential, or recoverable reserves. Please note that these estimates are of non-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 would like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob?

Thanks, Lisa. Please excuse, I have got a cold today so my voice is kind of off.

Good morning to everybody and thank you for joining us today. As Lisa mentioned this morning, we released our financial and operating results for the fiscal second quarter, so we are just going to review some of the key events and numbers and projects. Sterling McDonald, our CFO, will provide some additional information on the financial numbers and then we will take your questions.

In the second quarter we focused on continuing the development of our Giddings Field acreage under our joint venture. We also drilled our first well in mid-depth Haskell County, Oklahoma, shale project. We further benefited from the growing production at Delhi, which is continuing strongly as we enter calendar 2011.

As we bring on new production in the Giddings Field and in Haskell County, Oklahoma, over the next few weeks and as our Delhi production continues to grow, our cash flow and bottom line should improve substantially, obviously subject to commodity prices.

Now let's give you an update on our various projects. At Delhi we realized a 37% increase in production volumes to a total of 6,266 net barrels of oil in our second quarter. As more of the producer wells in initial Phase I respond to injected CO2 these volumes continue to grow and we expect to see much higher sales volume in Q3 based on production to date that we have seen in Q3 of 2011.

We are also pleased that the first CO2 injection in Phase II began in late December. Phase II is more than double the size of Phase I in terms of total number of wells. We should see production response from Phase II later this year. Phase III, which is similar in size to Phase II, is being installed in the field in calendar 2011 and the remaining two phases, IV and V, will similarly follow.

Our independent reservoir engineer has agreed with us that there is a good potential for expanding the project to other reservoirs within the unit. As previously announced, we have 9.4 million barrels of proved reserves and 5.7 million barrels of probable reserves, obviously all 100% oil. And a third of that is coming from our non-cost-bearing royalty interest. We currently expect not to bear any capital expenditures associated with our proved reserves.

At Giddings Field our production experienced normal decline plus what has been a temporary loss of production from one well. The overall production from 10 wells was about 51% oil and natural gas liquids. In our joint venture drilling project we have now drilled three wells. One well was just put on production and another should be connected to sales line shortly and the third is still producing back drill water.

As I mention in the past, we have found it's best to view the drilling in Giddings and the Georgetown formation as a portfolio that will typically have a range of results -- good wells, fair, and poor wells. So we would like to evaluate the program in the aggregate. So let's review those wells to date so far.

In September, we drilled the Supak-Brinkman in Burleson County which is a reentry operation with a single 4,100-foot lateral into the Austin Chalk. During drilling we lost an unusually large volume of water to the formation from our drilling fluid. While it's common to have to flowback 20% to 25% of that lost water, we have now produced back over 30% and we are still flowing back water. As a result, we now have minimal expectations for this well.

In contrast, during second quarter we drilled the Dodd #1 well, a well with two opposing laterals at 3,200 feet and 4,360 feet in the Georgetown formation in northern Grimes County. Immediately following the completion we did our normal wellbore cleanout operations which gave us some very strong potential production rate and pressure.

Production is expected to begin in February in the next week or two, subject to completion of our flowline connection to two different gas gatherers in our existing saltwater disposal well. It's important to note that we have four other development locations on our leasehold around this well.

In December we drilled our third well, the Lightsey-Lightsey in Brazos County with a single 4,560 foot lateral into the Buda formation. Keep in mind all these formations -- the chalk, the Georgetown, and Buda -- are all naturally fractured and therefore we don't have to put in artificial fractures.

Now the Lightsey only required a short gas gathering pipeline so we were able to get it on production in early February. Currently it's producing at a pipeline constrained four-day average rate of 1.3 million cubic feet, 124 barrels of oil per day. The gas being produced is very rich and is being processed for gas liquids so the overall production is very oily.

Now our share of capital expenditures for the three wells program to date is about $700,000. We are only paying about 10% of the cost. Our JV partner is awaiting production results from these three wells before making an election to participate in, and selection of, the remaining two option wells.

We are also exploring opportunities to enter into a second JV to develop the remaining drilling locations that we have in this program. And that would require an increase in our planned capital expenditures subject to whatever the terms of the JV are. Our goal is to get our production volumes in the Giddings Field moving back upward growth, both with the contribution of new production from the joint venture wells but also putting our best producer today, the Pearson, back to production.

In November the Pearson, we believe, was impacted by an influx of drilling fluid, water lost during the drilling of the nearby Dodd well. We believe that production -- actually, I shouldn't say we believe. Production has been reestablished in the Pearson well even before we put the Dodd back on production.

In Oklahoma, we have been primarily focused on our first test of the mid-depth Woodford Shale in Haskell County where we had over 8,100 net acres. We completed a reentry into the John Wells #1 at about 5,100 foot depth and successfully established good production. We are currently installing a short gathering pipeline connection and expect to commence gas sales later this month.

As we have previously announced, our first success in this leasehold are being conducted by reentering existing well bores which saves quite a bit of cost. These vertical wells do not require large fracks and consequently total well costs are less than $500,000 for a brand-new well and half that for these reentries. And expected production expense can be very economic even at current gas prices.

Our 8,100 net acre position spreads over 30 sections giving us potential exposure to more than 18,000 gross acres for development through force pooling.

We also are engaged in unitization of our second location in Haskell County and we expect to begin that reentry work in March. The unitization process allows us to force pool additional acreage and thereby increase our leasehold position while holding the leases through production.

In Wagoner County, which is the shallow Woodford play, we continued our production test in the Limon #1. It's an extensive de-watering operation which lowers the reservoir pressure which allows the gases to flow. The Limon is in the eastern most block of four acreage blocks there.

To date we have had a good test in our westernmost block, but our test for our southern block was suboptimal. It didn't work out as well as we would like. Based on the results today, we are selectively allowing certain leases to expire there without exercising our renewal option.

In the artificial lift technology effort we are continuing our extended negotiations for a first joint venture application of our technology. The third party we are working with has identified two wells to be tested and is working internally to complete the joint venture details, but as we have previously reported progress has been a whole lot slower than we would expect or even desire.

We have recently entered into early-stage discussions with two other operators to apply this technology in the Giddings Field and expect to apply it in at least one more of our own wholly-owned wells later this year. With that I am going to turn it over to Sterling.

Thanks, Bob. Let me just say that the big picture here is that our losses are narrowing with (inaudible) Q2 of the current year having improved 34% from the prior year's quarter. I think the financial results are fairly summarized in the first section of our press release so I won't bore you by reading it, but I see the big picture as this.

First of all, our losses are narrowing, as I said, showing a 34% improvement from the prior year's quarter. Secondly, our field income is improving as lower production is more than offset by lower field expense and higher product prices. On this point we expect that production is at a nadir and as we look forward to new production coming online at Giddings and serious ramp ups beginning at Delhi.

Three, our cash G&A remains basically unchanged and this has been true for many sequential quarters. Fourth, our cash flow from operations before changes in working capital has remained modestly positive. As you probably know, in looking at this metric we have bobbled on both sides of the positive and negative line but pretty much been a breakeven for -- I have to go back and look, but I imagine it has been for two or three years now.

Due to the nature of our royalty production, increases at Delhi will fall straight to the cash register in our pretax bottom line helping our cash flow from operations tremendously. Our balance sheet is strong with no debt and, although working capital has shrunk, it has been due to additional investments in our business and not as a result of burns due to our overhead.

Working capital was $3.2 million on December 31 as compared to $4.9 million on June 30, 2010. Of the $2.3 million of capital expenditures that we incurred during the six months ending December 31, 2010, about $765,000 was for lease holds, acquisitions, and about $1.5 million was for development activity.

Looking forward, assuming field income continues its improvement, working capital should also be at a relative bottom allowing us to complete the current year's capital program from our own sources of capital and hopefully building working capital modestly along the way. Obviously, though, there is little room for additional capital expenditure until operating traction takes hold further or additional sources of financing are obtained.

I would like to also point out that unlike many of our competitors we have never experienced a write-down to our full cost pool. We know that such charges are routinely dismissed due to their non-cash nature, but when overlooked it results in a depletion rate that is far short of full cycle finding and development costs.

In our case, we have been very fortunate in being extremely capital efficient resulting in a low depletion rate in the $4-plus dollar range that is pure and indicative of our historical full cycle F&D costs. In our business $15 is a respectable bogey, especially when speaking of a portfolio that consist of 90% or more of liquids such as ours.

In summary, finances and life are never perfect, but finances and life look pretty good here at Evolution Petroleum. I will now turn it all back to Bob.

Thanks, Sterling. We are quite pleased, extremely pleased, that production volumes at Delhi are rapidly increasing from Phase I. In addition, Denbury is now implementing the first of the large-scale expansion phases.

Initial results from our JV drilling program at Giddings in aggregate are attractive so far. As a result, we think that our next quarter results will be substantially improved both in volumes and revenues and also in the bottom line, assuming current prices hold up. In addition, in the second half of the fiscal year we should start realizing meaningful contributions from our Haskell County properties.

With that we are ready to take questions. Operator, please open the line for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Morning, guys, nice color. Say, Bob, just wondering in the Woodford Shale when you talked a little bit on Haskell County as far as the forced pool, wondering what kind of acreage we are talking there you could increase with that. And are you seeing other potential acreage pieces you could sort of add on around that as well?

Sure. Like I said, we have 8,100 net acres there, but that is spread over 30 sections. So a section being 640 acres that adds up to about 18,000, 19,000 total acres that we could force our way into so that would add another 10,000 to 11,000 acres potentially.

Now some of that we will participate as working interest, but probably the majority, I would think, would end up leasing to us under terms that are specified by the court that is overseeing the unitization process. And so I think it's a reasonable target to say we could look at possibly doubling our acreage position, which would be very attractive.

Okay. And then over at Giddings, it sounds like I think you understand that -- I understand I guess the issue you had with the one well. What is the plan? I guess, have you laid out for the rest of the year how many wells do you anticipate drilling or how many rigs do you anticipate working there for the remainder of the calendar year?

Sure. Well, our JV allows for up to two more wells. The partner has the right to select the two locations that they want to do, if they do any at all. Obviously, they have the right not to participate. But our CapEx budget assumes that we will drill two more wells in that well was in that program.

Given that our fiscal year is just through June 30, I would think that it's unlikely that we would do more than those two unless we did start up a new JV which is something that we are certainly working very hard to make happen.

Got it. Then just two more questions, if I could, on Delhi. To Sterling's point as far as when that really starts ramping up and drops immediately to the bottom line have you started thinking about, now that the timing is becoming closer, plans with that cash given you have no debt on the balance sheet?

Is it just look at acquisitions? Is it look at what you have and continue to expand your drilling? Obviously besides the pool that we talked about in the prior questions. I am just wondering about your thoughts now that we are getting closer to that point.

Well, it's somewhat difficult for me to start getting too expansive on that kind of a topic because that is something that the Board of Directors gets to weigh in on obviously. The initial thought is that that is why we have these other projects is to give us a large pool of development drilling opportunities that are close to a [factory type] approach, particularly up in Haskell County. That potentially could be well over 100 locations to drill at very, very low cost gas.

We do have these additional 10 or so locations to drill in Giddings. That would be a use of cash over the next year or two.

We are fairly confident -- I have got to be careful about this because it seems like it has taken on forever. But we think that this artificial lift technology has got a lot of potential. We just have to get through the hurdles of getting it demonstrated.

If you ever worked with a large public company before you know the internal politics can be very tough to get through, so that is what we are doing, we are wading through all these issues. But we think that has got a lot of potential. We could end up doing hundreds of these applications just in Giddings Field alone.

So we think we have a fair range of opportunities to deploy capital very efficiently and to very accretively and value to the shareholder. One thing we are not going to do is, just because we have cash, go out and spend it. That is one of the reasons we like to point out that employees own 20% of the Company on a beneficial basis.

Everything we do we look at and say, okay, this is coming out of my pocket. Is this what I would do with my own money? And so we are very careful in all these projects that we do.

Okay. And then last, a good segue into as far as that artificial lift technology in the press release it does talk about the first joint venture application. I am just wondering how do you go about or what is the sort of compensation structure going to look like or is that still being determined?

You mentioned all these potential -- 100 or so potential applications. I am just wondering now if you worked that out would each partner be separate. Is there kind of a mythology or how will that be worked out? I guess I am not necessarily doubting the technology as much as just curious about the payment structure.

Well, that is something that is part of the negotiation. People are very reluctant, as you might imagine, to sign over mineral rights for something that they don't know anything about. So early stage we more than likely are going to be doing a case of installing the technology in exchange for a fee per barrel or net profits type contractual right, just for a demonstration.

Now whether or not that is the case going forward or not I couldn't tell you. Ideally, what we are doing is we are looking at wells that are at the low end of their productive life. They have typically made a fair amount of reserves but they are now approaching a marginal type of operation. And so what we are doing is adding incremental -- substantial incremental reserves compared to what they are and we think that adds a lot of value.

If we can add 20,000, 30,000, 40,000 BOE of reserves to a well for $5 a BOE in the ground, we believe that that has a lot of value. Obviously, the other side is contributing a mineral interest and a wellbore and facilities, a pumping unit, tanks, and so forth, so that all has to be valued into it. We try to approach it that it's kind of a contribution of they contribute the minerals, they contribute the facilities, we contribute the technology and the cost of installation, and then we kind of share the benefit of that.

So that is obviously -- it's going to be a case where I suspect that negotiations for every deal will be different. Some are going to want a fee, some are going to want participation; it will just vary.

Got it, got it. Thanks, guys. Nice quarter.

Thanks, Neal.

(Operator Instructions) Dick Feldman, Monarch Capital.

Good morning, guys. No mention was made of the project you had in Texas.

South Texas?

Yes. What is the status of that?

That is our Neptune project. We finally, in the first quarter, late in the first quarter actually, end of November, finally got our permit from the state to allows us to dispose of water that we had had pending for many, many months which allowed us to restart production, which we did. Allowed us to start our production test.

The first producing well has been steadily making about two barrels a day, which is far less than what we were expecting. So I think it's -- I might have mentioned earlier in our last call, we are just being very careful on that project. We don't want to go throw in a bunch of money until we know for sure it's worth it.

Since the initial results are limited, we are going to just continue to produce that well and see if it cleans up and does any better. In the meantime, I am not putting any more capital into that project. In fact, some of the outlying leases we are letting expire, keeping just the core lease.

Okay. And going to Haskell County you said that you thought, depending upon the results of the unitization, that you could have as much as 100 locations. Would you be able to give us what your finding costs would be or roughly what the reserve potential would be with that?

It's really early on. Anything I gave you now would be, as my CFO just muttered under his breath, purely speculative, but we are looking to try and get it less than $1 an MCF.

Okay.

And even at current product prices that could be an attractive investment opportunity, even though it's not popular right now in the market.

Because it's a -- oh, because natural gas is not popular.

That is right.

These wells aren't going to cost us but $400,000 to $500,000 a piece. They don't require a big frac. In fact, they don't even require much of a frac at all.

We have had some kind unique water handling facilities that we are installing that seem to be working great that helped to drive down the operating cost, which is always -- in this area is a big issue is how you handle the water. People that have to haul the water off at $1 and $2 a barrel quickly give up on the project because of the operating expenses. We think we have got a way and are demonstrating it to ourselves that we can handle that water for a very small fraction of that cost, which then opens up this opportunity.

So as you know, Dick, this is a relative business in terms of what you spend for what you get. We are really indifferent as to what the products are as long as the relationship between F&D, operating, and product prices are --.

Sticking again to the Woodford, in Wagoner County you have talked about some disappointment in the southern part of the acreage. Do you think you will go ahead in the other part or still you don't have enough data to --?

Well, we are considering our testing. As I said before, we had had four blocks all together -- a western block, a southern block, eastern, and northern. The western block tested great. It was a spectacular win for us.

Then we went to the southern block and that did not work out very well. Now we are on the eastern block and we have got that well testing and going on. It's too early to make a final determination, but it's not blowing our socks off. We have not tested the northern block yet.

Until we have a real good handle as to what works and why it works, it's hard to spend a lot of time and effort up there. And so what we are doing is we are making sure we keep our leasehold together around the areas that work and less so in the areas that don't work, or at least don't work today.

You mentioned earlier in the call that I think you spent about $760,000-odd on lease holds. Where were those expenditures, in new areas that you have not mentioned yet or are they in existing areas?

It's mostly in existing areas, primarily in lease renewals and maybe picking up odds and ends of leases around existing projects and so forth. It's mostly existing areas.

Okay. Thank you and keep up the good work.

(Operator Instructions) Mike Grijalva, Global Hunter Securities.

Just a quick question for you guys. In the Giddings Field you guys did about 16,000 barrels this quarter, 21,000 in the first quarter. Do you think you guys could get it back up to that 20,000 barrel mark third, fourth quarter?

Our production should be substantially improved because of the wells we are bringing on from the JV program plus the fact that we are getting our Pearson back online and it can start contributing. So I am not going to tell you exactly what kind of a target number, but we should see -- I would think we should see a substantial improvement in Giddings in the third and fourth quarter.

Yes, and especially in the fourth. We are already halfway through the third quarter and the new production is not online yet, and Pearson is just looking like it's starting to come back. So we only have a half a quarter to work with right now.

I think from an overall standpoint we will probably see some pick up at Delhi that will help the numbers in the third quarter, but the fourth quarter we ought to see more contributions from Giddings.

Okay, great. And that Pearson well, what was that producing before you guys encountered those challenges?

It was making about 15 barrels and about 500 MCF a day.

Okay, perfect. All right, guys. Thank you very much.

At this time there are no further questions. I would like to turn the call back over to management for any closing comments.

Thank you for listening this morning and supporting the Company. Feel free to give us a call anytime and we will be happy to relate any other publicly available information to you. Thanks again.

Ladies and gentlemen, this concludes the Evolution second quarter of fiscal 2011 earnings conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3030 followed by a pass code of 4406348.

ACT would like to thank you for your participation. You may now disconnect.