Evolution Petroleum Corp (EPM) 2010 Q4 法說會逐字稿

Good morning, ladies and gentlemen and thank you for standing by. Welcome to Evolution's fourth quarter earnings 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, Monday, September 13, 2010. I would now like to turn the conference over to Lisa Elliott, Senior Vice President, DRG&E. Please go ahead, ma'am.

Thank you and good morning, everyone. We appreciate you joining us for Evolution Petroleum conference call to discuss results for the fourth quarter and full year fiscal 2010 which ended June 30. Before I turn the call over to management I would like to go over a few regular items. If you would like to be on the Company's e-mail distribution list to receive future news releases please call DRG&E. That number is 713-529-6600, somebody would be glad to will help you. If you wish to listen to a replay of today's call it will be able in a few hours via webcast by going to the Company's website at www.Evolutionpetroleum.com or via recorded replay until September 20, 2010. The dial-in number and pass code can be found in the earnings release that Evolution put out this morning. Information recorded on this call is valid only as of today, September 13, 2010 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 statements which are based on management's beliefs as well as assumptions made by management and information currently available by management. Forward-looking information includes statements regarding expected future drilling results, production and expenses. Although management believes that expectations reflected in such forward-looking statements are reasonable they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks 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 and possible reserves or use terms like volume, reserve potential or recoverable reserves. Please note that these estimates of nonproved reserves or resources are by their very nature more speculative than estimates of proved resources. Accordingly are subject to substantially greater risks. Now with that I would like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob.

Thanks, Lisa. Good morning to everyone. Thank you for joining us today. Sterling McDonald our CFO is here to provide details on the financial results and help answer questions later. As Lisa mentioned this morning, we released our fourth quarter and year-end results, recorded our reserves as of year-end 2010 and provided an update on our operations and plans for this upcoming year. Hopefully you've had a chance to review that release. Sterling is going to cover the financial highlights in his remarks and am going to do an initial overview and then focus on reserves. We finish up our prepared remarks with a discussion of our plan for 2011. We'll be certainly glad to take any questions you might have later.

As an overview, we're very pleased with the results for the year given the limited $3 million capital budget that was focused really more on project testing and production development. We essentially hit our net production target of about 126,000-barrels of oil equivalent and generated about $5 million revenues. Our loss of $2.4 million which is improvement over last year included over $2 million noncash stock compensation. So we really generated positive cash flows to cover much of our CapEx. More importantly, we achieved several milestones in 2010. First and foremost our EOR project at Delhi moved in to a proved producing category with the first CO2 injection last November. The first production last March and now first proved reserves on June 30. Second, we entered into a joint venture for the first development drilling locations at Giddings. The first well which is now drilling in the horizontal section in Pearson.

Third we have made considerable progress in advancing the commercialization of our artificial lift technology through discussions with industry. Fourth we have progressed in the testing of our Woodford shale potential in Oklahoma and our infill oil potential in south Texas. Last we did all of this accomplishing milestones without diluting shareholders or taking on debt. As far as reserves go our proved reserves as of June 30, 2010, are now 12.4 million-barrels of oil equivalent which is over 300% increase of the prior year. This increase is primarily due to the upgrade at Delhi based in large part on first production from Phase I of the project. Denbury, the operator is currently installing and funding Phase II and III in the field. We also realized our first reserves in Oklahoma, although the amount is really very limited to just those leases around one test well. The pretax cash flows this kind of 10% of our total proved reserves, our PV10. Increased by 642% to $266 million compared to $36 million last year. The PV10 is based on the new SEC pricing of the average trailing 12 month first day NYMEX prices or about $76 of oil and $4.10 per million BTUs for gas. Please note that our proved reserves are 83% black oil, 8% gas liquids and 9% natural gas. So we're quite oily.

Our independent reservoir engineers further assigned probable reserves of 7.2 million BOE with a PV10 of about $64 million. The probable reserves are down compared to last year since we upgraded about 9.4 million-barrels from proved status with Delhi, offset by the additions of about 1.5 million-barrels of probables at Delhi.

I will now cover the various fields that we have got in more detail. In Delhi, we added again 9.4 million-barrels of proved reserves, the PV10 of $224 million, a 3.4 million-barrels of those proved reserves were late to our royalty interests which are noncost bearing. They have no operating costs or CapEx associated with them. Proved reserves associated with our reversionary working interest don't require any projected capital expenditures by Evolution over the time period going forward. Our probable reserves at Delhi are 5.7 million-barrels with the oil with PV10 at $51 million of which approximately 1.6 million-barrels relate to our royalty interest. Combined proved and probable reserves are 15.1 million-barrels of PV10 of $276 million, that's about 11% increase in volumes over the last year. Based on the early response performance and the higher CO2 injection rate, the growth expected recovery of oil at Delhi has been increased from 13% of the original oil in place up to 17%. The benefit of the increased recovery of oil is partially offset by the cost of the required additional purchases of CO2. These purchases are heavily weighted to the initial years of that project. Although we are not responsible for any field operating costs until Denbury reaches defined payout and reversionary interest becomes effective, that $200 million defined payout is calculated as total revenues less field operating expense including the cost of the purchased CO2.

The additional purchases are expected to extend our prepayout period but we still expect payout to occur some time in or around 2015, 2016 time frame based on the NYMEX oil price of about $76 per barrel plus nominal inflation. Our (inaudible) working interest is also slightly less now at 24% due tile adjustments. Denbury is rolling out Phases II and III of the development at Delhi while maintaining field production for Phase I and increasing CO2 injection volumes. At Giddings, visions and extensions of proved reserves replaced about 76% of our 119,000 BOE of production there in the field last year. And we have essentially maintained our net proved reserves of about three million BOE. PV10 increased by 17% over the prior year to $41 million primarily due to the high grading of our 19 well development drilling portfolio. This is somewhat offset by the higher than expected or a little bit higher expected drilling costs. Proved reserves at Giddings are 28% oil, 35% gas liquids, and 37% natural gas. Proved producing reserves at Giddings increased slightly by about 4% to 450,000-barrels equivalent with a PV10 of a little over $8 million. Probable reserves there are about one million BOE with a OV 10 of about $12 million. Probable reserves consist of two drilling locations and incremental reserves, associated with five drilling locations.

We currently have ten producing wells in Giddings from which we averaged net production of about 213 BOE per day in August. And in early July, we announced a joint venture with the industry partner to drill up to five horizontal development wells in the Giddings field. This is from our portfolio in the Austin Chalk and Georgetown formations, and Burleson and Grimes county in central Texas. We are drilling the wells as operator. We have a 20% working interest before payout and a 38% working interest after payout. We only pay 10% of the drilling and completion costs. We spud the first well in August, in Burleson county, (inaudible) it is a $1.7 million reentry operation with 3800-foot long Austin Chalk collateral in two of the existing well bore.

The second well in the JV, the $2.9 million grass roots well located in northern Grimes county. Our expected net capital expenditures for a five well program are about 1.2 million. If we drill all five Wells we will be completed in early spring of 2011. We're also exploring opportunities to do a second JV to finish our portfolio. This would require an increase in CapEx budget. In south Texas and Lopez field, we are testing an infield development concept in a well that had been previously drilled by other operators. Our test began late in the second fiscal quarter of 2010 with the drilling of two infill producers and the reentry of two previously banded wells for water injection. Due to delays in repaying electric power service and mechanical problems with the reentered ejection wells we really weren't able to begin effective testing until the summer.

Given the limited testing information and injection problems at that time, we did our reserves on as of June 30, we elected to take the conservative approach and reclassify the small amount of reserves there, proved reserves, 48,000-barrels last year, put those back into the probable category. Otherwise we maintained the overall reserves assignment in the fields, proved and probable about 300,000-barrels PV10, $800,000 associated with 25 wells. The engineers further assigned the same possible reserves in 2009 for these wells. Since further testing, we are at full development we've identified up to 92 additional infill locations for the balance of our lease hold. We believe we have corrected problems with the injection well and now have adequate water injection capacity in the field for more extensive testing and it has already begun in one existing producer and two additional producers planned for 2011.

In Oklahoma we are continuing to test the productivity of the primary Woodford shale in four blocks of our 9000 plus net acres of Wagoner county to determine the best completion practice and development plan. As previously announced we drilled a Henry 19-2 in our westernmost block and achieved greater success and expect it with a peak trade of about 93 MCF a day, before (inaudible) traders from storms ended the test. Independent reservoir engineer assigned proved developed nonproducing reserves to that well, about 138 million cubic feet, to further assign ten probable locations directly offsetting that well for about 1.4 BCF net. He's also signed possible drilling locations.

Now, at current SEC pricing the PV10 is nominal for these particular reserves. Knoche well in our -- especially those volumes. Knoche well in our southern leasehold utilized a different completion method and was substantially less productive than desired so we are going to have to do a second test well in that leasehold before making a decision about that particular block. The Limon well in our eastern leasehold block was tested at Caney and confirmed that Caney shale was likely to be only a modest increment to production and we're currently preparing the test in the woodford. We are also keeping an eye on the results of other operators on eastern side of our acreage at shallower depths. Ultimately we expect to bring in JV partner to advance that development in Wagoner county.

Haskell county further south, we own over 8,000 acres, we expect to reenter two existing vertical wells and test the Woodford shale at depths of about 5,000 feet, and that testing was delayed from late in fiscal 2010 due to an extended focus on our other test work that we are doing. Artificial lift we are continuing to actively pursue commercial JVs utilizing our proprietary lift technology. We hope to announce a JV agreement in the next few months. Based on test results at Giddings we believe our technology can reestablish production in many wells throughout Giddings and other fields, developing horizontal wells where liquids are associated with production. We are currently negotiating with a major producer at Giddings and entering discussions with second producer as well. The idea of providing technology and some capital in order to gain interest in the reestablished production. We also plan on approaching other producers for applications outside of Giddings. The current slow pace of this commercialization effort is really due to the nature of introducing significant change to field operations. We are convinced that our progress is very real and substantial. Now I'll turn the call over to Sterling and talk about financial results for 2010.

Thanks, Bob, and good morning to all of you. Fiscal 2010 was a pivotal year in which we achieved some important milestones. Certainly the reserve additions that Bob discussed for the spotlight story but our financial results improved as well. On a quarterly basis, we had sequential improvement in all four quarters of fiscal 2010. Year-over-year, our quarterly loss narrowed 39% from 1,130,000 for the quarter ended June 2009, the $675,000 loss for the quarter ended June 2010. Increased product prices played a key roll to offset our flattened production decline rates at Giddings, the total operating expenses declined each quarter as well. On an annual basis our financial improvement was similar but more muted narrowing our loss 8% despite a 12% drop in product prices where we saved on a BOE basis.

For the year ended June 30, 2010, we reported a net loss of $2.4 million or $0.09 loss per share, which included $2.1 million of noncash stock comp expense. On total oil and gas revenues of $5 million. This compares to a net loss of $2.6 million or $0.10 loss per share on total oil and gas revenues of $6.1 million for the year ended June 30, 2009, which also included $2.4 million of noncash stock comp expense. $1.1 million decrease in revenues was offset by decreases in operating costs of approximately $1.2 million primarily related to a decrease in G&A and depletion and an increase in our income tax benefit of $133,000. At the field level, in other words, operating income before corporate G&A and income tax we were profitable for the year and each quarter meaning that we recovered more than our depletion rate after all production expenses were charged.

Looking forward, improvements in our financial results should be more favorably driven by our expected increases in production at Delhi, for some marginal improvements through the JV development of our reserves at Giddings combined with an extremely low depletion rate under $5 BOE arriving from the 12.4 million BOE additions of proved reserves we had in 2010. This is combined with the continual hold on our expenses at the corporate level looking forward. I should note that the $4.39 depletion rate we recorded in Q4 '10 is reflective of our full cycle finding and development costs given that we have never had a write down to our full cost pool in the history of the Company. Granted this rate is driven by the terms of our Delhi interest which are quite large but it is what it is, quite low for the benefit of all of our shareholders. Over the last year and a half, as we have directed our focus to field R&D and concentrated on preserving our liquidity our drilling activity was limited and so production decline was natural. During this time, we have been able to gain a better understanding of the best ways to develop our leases in Oklahoma and south Texas, as well as commercialize our proprietary technology and our testing in our oil project in south Texas.

So let's turn to our liquidity and future development needs to be funded. At June 30, 2010, our working capital was $4.9 million we continue to be debt free. This compares to working capital of $7.6 million at June 30, 2009. The $2.7 million decrease was due primarily to investments of $3.7 million and oil and natural gas properties which included $0.5 million for leasehold acquisitions and $3.2 million for development activities. Cash flows provided by operating activities for the year were [$3 million]. As Bob mentioned, the Board of Directors approved a capital budget of $4 million for 2011 which we will fund with cash on hand. We expect the revenue from the Giddings field to be -- approximately cover our cash overhead and we have no debt service, while looking to increasing Delhi production to provide our base capital expenditure plan during fiscal 2011.

Should we decide to escalate our drilling activities we can look to additional JVs, project financing or any number of options included in our shelf registration. However we proceed in the funding of additional expansion please bear in mind our promise so increasing per share values for our shareholders including the 20% ownership employees of our Company enjoy.

In summary, we have a great balance sheet with $31 million of equity and no debt, a PV10 of our proved reserves of $266 million and when combined with our probable reserves, $330 million. And our operating results are improving.

With that I will completes my comments and I will turn the call back to Bob.

Thanks, Sterling. Just a few more comments about our plan for going forward. As the year progresses and we obtain additional data, we may decide to expand our base plan for the year and accelerate development to any one or more of our projects. We will fund that as Sterling said through any one of a number of different methods. Currently we plan to in our base plan drill up to five wells in Giddings and our JV and complete two workovers at a total cost of about $1.4 million. We are going to continue our testing program in south Texas, continue reentries, the cost there is pretty nominal. We are going to continue testing in Oklahoma with two new wells in Wagoner and two reentries in Haskell, costs cleared up to something about $700,000. We're going to initiate a JV -- we plan to initiate a JV utilizing our artificial lift technology and we've set aside about $600,000 for -- to share that cost. And we are going to maintain our core leasehold with option exercises and lease renewals we are expecting that to be about $1 million of costs.

As Sterling said we are very encouraged about 2011. As we look to better define our opportunities. Early stage R&D work can be -- appear to be slow moving. We have made some very important progress, being deliberate and very prudent to optimize the outcomes for the Company. Our strategy is to limit the amount of capital risks, take the time to better define the opportunity, and maximize value created and then bring in a partner or partners to full scale development as warranted. And with that we will take any questions that you might have. Sterling wants to say something.

Yes. I've got one edit here. I mentioned the cash flow from operating activities. I think I said $3 million I meant to say $2.3 million for fiscal 2010.

Thank you. With that, operator we will take questions.

Thank you, sir. We will now begin the question and answer session. (Operator Instructions). And our first question comes from the line of Jason Wangler with Wunderlich Securities. Go ahead, please.

Morning, guys, nice quarter.

Thanks, Jason.

On the Giddings transaction that you guys already announced obviously, there's between two and five wells, can you describe what would be the cause to have it be two wells versus five? Is there something in the contract that states that, or is it just more of you guys getting together and saying, let's keep going or let's pull back?

Well, it is going to be really a function of two main issues. One is the cost of the wells, and second is going to be commodity prices. These wells are a mixture of oil, gas liquids, and gas. So, for the exposure to all commodity gas, all commodity prices, obviously the high liquids component helps offset the current low gas prices.

Part of the interest by this other party in this JV is our ability to get these wells down at an attractive price. And so, what they're looking for us is to prove that we do what we do. And they want to have the ability, if we aren't able to perform on our AFE costs, to back out of the last couple of wells.

Okay. That's just kind of what I was looking for. And then just maybe one for Sterling, you mentioned on the DD&A rate, you're looking at something under $5. Is that -- do you think that's going to be for the full year?

We booked $4.39 for the fourth quarter, which was -- the fourth quarter we adjust our depletion rates under GAAP. It was running $17 I think in the previous quarter, and for the year netting in that $17 range. But yes, going toward we have a much larger base of proved reserves, and of course, many of the reserves that we added have no appreciable capital costs associated with them. I think we moved -- we only had $1.9 million of investment on our books for Delhi after the farm-out, and with the booking of these reserves we moved $1.1 million of that $1.9 million over into the full cost flow.

So, there's some legacy costs left, but it would more than be absorbed by any anticipated increases in proved reserves as we go forward. But that $4.50 is going to be with us over the next year probably.

Okay. Great. Thanks, guys.

Thanks, Jason.

Thank you. (Operator Instructions). And our next question comes from the line of Joel Musante with CK Cooper & Co. Go ahead, please.

Good morning, guys.

Morning, Joe.

Good job on booking those reserves, congratulations.

Thank you.

I just had a general question. How are you prioritizing your projects, in other words, if you were to ramp up activity from one of those projects, where do you see the capital being focused?

Right now, Joel, I can't tell you which projects are going to take priority, simply because we are still in that testing phase. Obviously, Oklahoma is somewhat burdened by gas prices. With gas at $3.80, it's hard, no matter how good a project is, it's hard to justify spending a lot of capital to produce gas at a sub $4 price. And so that obviously tempers any development activity there. In Giddings, the opportunity there right now is primarily with our existing JV, which we are very active with in terms of drilling those first five wells. That could be expanded.

We're also in discussions to add a second JV in that area. We are very excited about the opportunity to apply our artificial lift technology in the Giddings area as well. That is an active project that could easily expand. In south Texas, that is another project that could easily be expanded quickly.

Keep in mind that, on our reserves, we have to do that as of June 30, based on the information we have at June 30. But we actually can have the benefit of additional testing work since then. So we're cautiously optimistic that that's going to also be an attractive place for us. So right now, I really can't tell you which of those is going to be the one, but artificial lift technology certainly is attractive right now, but until we have a better idea of where commodity prices are going, these last test results, I can't tell you for sure.

Okay.

I am going to follow up on that. The artificial lift technology, if we can get legs with that, we can build a whole company around that opportunity, and it is not just production that's gone down in the last ten years in this country. It is for horizontal well bores that have liquids associated with their production that are being drilled in the last ten years, and ones that are being drilled now would replace inventory in the future. Eventually all of those horizontal wells will load up if they have liquid, and that even includes oil plays such as the Bakken.

And on Oklahoma, we planned that whole project around $5 gas prices, and at the time we thought we were being very conservative in terms of what the market might see, because gas prices were going from $6 to $15 an [M], and we're planning a project for $5, and now we're finding out right now $5 is not achievable. So as Bob says, there's a lot of moving parts. And we will be opportunistic where we can find, given value.

Okay. To date, I mean what are you seeing from the performance from the artificial lift technology?

What do you mean-- we have installed the one well, it mechanically is doing exactly what it is supposed to do. We actually installed a form of it in another well, and again, it appears to be doing exactly what it's supposed to do. We've shown these results to various operators, we've gotten a high level of interest, and we are actually working on a definitive agreement with one party. We are in discussions with a second one, and we are looking for where we can do this outside of Giddings. And so we are excited about the opportunity, but until I have a signed agreement, it's not a signed agreement.

Okay, well, great. Thanks a lot.

Thanks, Joel.

All right, take care.

Thank you. (Operator Instructions). And our next question comes from the line of Robert Kecseg with Las Colinas Capital Management. Go ahead, please.

Good morning.

Morning.

I just was wondering if you could explain -- I guess just elaborate on Delhi, when you talk about phase I, II, III, is that just them adding more well bores to the injection?

Sure. They had the whole project. And keep in mind, this project covers 13,000 plus acres. We can't do all of that at once. And so what you do is, you do it in phases. Each phase is focused on a portion of the field, where you put in first injection wells to start to fill in the reservoir with the CO2, and then you add your producing wells. Once the reservoir is pressured up, then you start production, and then that rolls into your gas processing handling facility where you clean up the gas, and repressure it for reinjection.

So, what you do is you manage that process because you can only spend so much money, and do so much work in the field, and be effective. That's what Denbury's found in all of their projects, they actually have it down to pretty much to a science in terms of how much they can do on a year by year basis in a given field. In this particular case at Delhi, the project is divided up into I think roughly five phases of where you take the original plan of somewhere in the 250 to 300 well bores to be drilled and reentered for the whole project, producers and injectors, and you divide that up into say, blocks of 50 to 60 wells.

And so the first phase has been done with about some 22 wells, I think it is. That's the phase that's currently producing. Phases II and III are being installed, and when I say being installed that means wells are being drilled, wells are being reentered, flood lines are being laid and so forth out in the field. It is being connected into the processing producing process facilities.

Does that answer your question?

Yes, and as far as future changes in reserves relative to Evolution, do those different phases, and the expansion of that give any potential for that to increase to any degree?

Well, sure. As you might remember, what I said was at Delhi, we had about 9.4 million barrels moved into the proved category. However, we also have another 5.7 million barrels of probable reserves, which are going to be moving to proved category at some point in the future, obviously subject to performance and so forth. So we have that to look ahead to. In addition to that, we believe there's considerable room for upside improvement by the increasing in the size of the reservoir that's expected through all of the 3D seismic work that's being done by Denbury, there's a possibility that that's going to lead to a larger tank.

There's also a possibility of increased recovery as a percentage of original oil in place. We started off last year, which is the probable reserves, we had a 15% recovery, this year they moved that up to 17%, Denbury actually is getting higher than that in other projects. We have the possibility of higher recovery. There's also the possibility, as it's being explored, of converting this to a WAG process, which is a water alternating gas process, that has the potential of reducing the cost, reducing the amount of CO2 required. And there's always a possibility that you increase your recovery, but I think it is primarily focused on reducing the cost of projects.

So we have quite a few possibilities for increasing our total reserves in the project. But keep in mind the whole field has produced close to 200 million barrels of oil from primary and a partial secondary process. Typical projects, when you look at primary, secondary, tertiary, you'd say roughly a third primary, a third secondary, a third tertiary, so that sets a much higher bar to shoot for your tertiary than what we are talking about here. We think there's a lot of room for upside over the next couple of years.

Right. And also, is the length of time for these to produce, is that extraordinarily long compared to other kinds of wells, as far as--?

Not really. Tertiary projects typically do have a long life. There are CO2 plugs in west Texas that have been going on since, shoot, the '80s, I believe. These are typically very long life reserves, the ultimate economic limit is really going to be driven more by oil price, as well as technology, and driving your cost down. So really, this CO2 project at Delhi is likely to have a life of 25, 30 plus years.

That is actually kind of a neat aspect to this project that I cover in my presentation. If you take the cash flow year by year, and reserve report, and if you say okay what's the PV10 every year of the remaining cash flow? That PV10 every year goes up for us, up until about the 2016 time frame. And the reason that that's intriguing is that, while your PV10 is going up every year, you are getting cash flow from the property. And so by the time you get to 2016 or 2017 in this project, your PV10 not only is 30%, 40% higher, but you've also pulled out over $100 million of pretax cash flow.

That's a real interesting concept, because what it says is that -- the current PV10 today is $275 million of 2P reserves at Delhi for us. If you add the PV10 plus cash received as of say, 2015, 2016, 2017, that total number is starting to approach $400 million or $500 million. So it is a real neat asset for us. Most people don't -- when most people look at reserves reported by companies, their proved reserves, they looked at total proved reserves and what is (inaudible) they tend to forget that a large portion of those are undeveloped, and there's a lot of capital associated with those.

Our proved reserves really have no capital associated with them at Delhi. It is all prepaid or being paid by third party. So, we really, I looked at this as kind of the prepaid PUD annuity for us.

Great. It also gives you more time to stretch out the rest of your projects.

Correct.

According to your own plan.

Right.

Okay. Great. Thank you.

Thank you.

Thank you. And we have no further audio questions at this time. I would like to turn the conference back over to Mr. Herlin for any closing statements.

Well, I thank you for all attending. We will be doing our presentation schedule this fall, and I will be out speaking to the world, going over this information with everyone. But we certainly welcome any questions that people might have to elaborate on this information we provided. I appreciate you again for showing up. Thank you.

And ladies and gentlemen, this concludes the Evolution's fourth quarter earnings conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3030 with the pass code 4360889. ACT would like to thank you for your participation, and you may now disconnect.