Evolution Petroleum Corporation (EPM) Q2 2010 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen, thank you for standing by. Welcome to the Evolution Petroleum second quarter of fiscal 2010 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, Tuesday, the 16th of February, 2010. I would now like to turn the conference over to Lisa Elliott of DRG&E. Please go ahead.

Thank you, Lewis, and good morning, everyone. We appreciate you joining us for Evolution Petroleum’s conference call to discuss results for the second quarter of fiscal 2010, which ended on December 31. Before I turn the call over to management, I go over the identical over. If you would like to be on the Company’s e-mail distribution list to receive future news releases, please call DRG&E’s office. That number is 713-529-6600, and someone will be glad to help you. If you wish to listen to a replay of today’s call it will be available in a few hours via webcast by going to the Company’s Web site and that’s at www.evolutionpetroleum.com or via recorded replay until February 23, 2010. To use that replay feature just call 303-590-3030 and use the pass code 4220160. Information recorded on this call today is valid only as of today, February 16, 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 information which are based on management’s beliefs as well as assumptions made by management and information currently available to 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. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected. Also today’s call may include discussion of probable and possible reserves or used terms like volume, reserve potential or recoverable reserves. SEC generally only allows disclosure of proved reserves in securities filings and these estimates of non-proved reserves or resources are the very nature or more speculative than estimates of proved resources and accordingly are subject to substantially greater risk. Now, with that I’d like to turn the call over to Bob Herlin, Evolution’s Chief Executive Officer. Bob?

Thanks, Lisa, and good morning to everyone. Thanks for joining us today. Sterling McDonald is here to make some remarks on financial and financing side of the business later in the call. Since we filed our 10-Q last Friday, we decided not to go in a detailed review of the numbers, but we will take questions you might have on those details. But, I would like to first update you with operations. As you might recall, during our last conference call in November, we mentioned that CO2 injections began in mid-November in a Delhi field in Northeastern Louisiana. Denbury continues to roll out their project and is now on Phase II. We still believe that first oil production response will occur sometime by mid-calendar of 2010, although our 0.5% reversionary interest won’t likely kick in for two years. We are going to be receiving revenue from the project in an initial production response through our 7.5% throughout the interest, throughout the life of project. We expect production ramp up as injection is extended throughout the field and it will be meaningful to us as early as the summer. We also expect initial production response in CO2 injection to support a reclassification to the significant portion of our probable reserves to proved category. In the meantime, we are continuing to test and develop our other projects and believe that these activities could position us for additional reserves growth. Our current focus in our Neptune oil project in South Texas and in our shallow gas shale project in Oklahoma is to perform production test that will hopefully position us for reserve upgrade as well as generate additional revenue. Maintaining a conservative expenditure program until higher cash flows in the future to support more aggressive plan. We believe that the best use of capital now is to improve the commerciality of our project and to delineate the potential for development. In the Neptune project Lopez Field, we have drilled two wells and we expect to have them on production following completion of the first water injection well through our re-entry of existing wells. This would be done sometime in the next couple weeks, weather permitting. We also have been working on expanding the number of potential in co-allocations, now that number up to about 112 sites identified which is obviously subject to the test with the first two producers. In the Giddings Field, we are currently focusing on maintaining our production, which is possible in controlling our costs with the objective of covering our total overhead expenses. We have nine wells on production in the Field with the tenth well about be put back on production after some repair work. During the last quarter they produced at a rate of about 340 net barrels of oil equivalent per day and this is down about 11% from our production with prior quarter. Although these wells have passed a stage of steep decline, volumes were negatively impacted during the last quarter by continued susceptive blockage within the lateral section of our Hilton-Yegua well; downtime in the Pearson well for two pin plug and downstream compressor repair; downtime on our Williams well for an installation of our artificial lift technology and compressor work on Deno [ph] which is the first well we saw at Garbarn [ph]. The plug in the Pearson tubing has been cleaned down and it rate went back to its previous 1.2 million cubic feet equivalent per day rate in January. Deno has been offline since late December, waiting unfortunately compressor we should get back on production shortly. The balance though the fiscal year we plan to inject a lateral clean house that Hilton-Yegua well that’s a plugging. Our capital plan does not yet include the drilling of any new wells at Giddings, so we are actively working on potential joint ventures to accelerate that development drilling. These operating costs including production tasks is in Giddings Field were up about 13% to some $12.37 per BOE, which is primarily due to addition of three producing wells in payment of prior year ad valorem tax, which is offset partially by the completion of our dedicated water disposal wells for the Pearson. We put that on the mill last quarter to lower bar handling cost. Including our depletion rates of some $17.04 per BOE, our Field income breakeven point is now slightly less than $30 per BOE. As I mentioned we installed our proprietary lift technology on such a well, the Williams during a normal work-over. We believe that it is a combination of that technology plus the normal installation of a rod pump has substantially enhanced its production as well as backed up about 160 Mcfe per day. We are also in an early stage discussions with third parties to potentially acquire that technology to their marginal uneconomical shutting wells in the Giddings Field and in another field. In Oklahoma, we are continuing our vertical well test programs in the Woodford and the Caney gas shale. We are pleased that the Caney shale well is testing favorably so far and consistently producing water free at a steady 25 Mcf/d rate, which we believe confirms that the Caney can contribute commercial gas volume as an add-on to our primary Woodford target. Initial test production in the Woodford formation well is promising both in gas rate and in water rate but the test productions are on hold while we deepen the associated large disposal well and with the water. And that work is underway and we expect to have that well back and test production shortly, again weather permitting. Goal in Oklahoma is to determine deep initial production rate in declining profile. We expect the results will allow us to design the appropriate development program, facilities and gathering system. Later in the fiscal year, with market conditions permitting, we plan to re-enter a well in our mid-depth project in Haskell County to begin similar testing of the Woodford and Caney Shale reservoirs at depths of about 4,000 feet to 5,000 feet. We believe that our acreage in Oklahoma holds substantial shale gas potential that we believe will be developed at a cost of $0.80 or $1.25 range per Mcf, which appears to be attractive in the current gas price environment. Now, with these operating results I will turn the call over to Sterling to talk about the numbers.

Thanks, Bob, and thanks all of you for joining in today. Since we filed our 10-Q last Friday, assuming that you have had reviewed at the earnings release we put out this morning I will just hit a few highlights and give a sense of what we are expecting for the balance of fiscal year. On the cost side, we expect operating cost, G&A and DD&A rates to stay in line with our second quarter. As for G&A, we should be able to maintain the absolute levels we recently achieved through our recent 25% year-over-year reduction in G&A. As lease operating expenses we may be able to slightly improve our 6% year-over-year decline per barrel of oil equivalent since the new salt water disposal well that Bob mentioned for the Pearson that’s not online in the full first fiscal quarter. As you may recall we extended about $425,000 of completed salt water disposal well at the Pearson to avoid something more than $30,000 of monthly water hauling expense. On the margin this reduce lifting cost over $6 a BOE on a substantial part of our production at current rate, while adding much less to our depletion rate. At December 31, 2009, our working capital was $5.7 million, down from $6.6 million at September 30 and $7.6 million at June 30, which reflects investments of about a $1 million per quarter in oil and gas property. Year-to-date, 95% of our oil and gas expenditures have been for development, of those 60% were at Giddings, 0.8% at Neptune, and 32% in our shallow shale property in Wagoner, Oklahoma. On liquidity, we continue to be debt-free, while cash flow from operations was positive during the second quarter, coming at a $297,000 including changes in working capital. Looking forward, we expect to maintain a conservative financial approach while managing to maximize share value over the next few years, without unduly diluting or risking the current or future value of our asset. With the Delhi project projected to begin and generating cash flow in about three months or four months and production we hope to build in our Neptune project we should be in an increasingly stronger financial position to develop our opportunities going forward. In the meantime we are also pursuing joint ventures which to provide further flexibility and opportunity for growth. That completes my comments. I will turn the call back to Bob.

Thanks, Sterling, and now we will be happy to take any questions.

(Operator instructions). Our first question comes from the line of Joel Musante with CK Cooper & Company. Please go ahead Joel Musante – CK Cooper & Company: Hi, Bob, hi, Sterling.

Hi, Joe.

Hi. Joel Musante – CK Cooper & Company: Hi. Yes, I just have one quick question. You talked about resuming your Giddings drilling program. Can you just elaborate a little bit more on that what you are looking to do as far as JV go?

We’re looking at a wide range of options. We’ll consider any one of, any number of possibilities ranging from sale of the whole thing to a farm out as a whole thing to farm out selected locations, we’re wide open to how we can accelerate that program and allow us to accelerate them our other projects. We still at the moment with where oil and gas price is hard that these locations are now imminently attractive and so far we have been pleased with the reception by instrument. Joel Musante – CK Cooper & Company: Okay, all right, so, you would potentially monetize this to invest in Neptune or the Woodford project?

Certainly, the possibility, I suspect, in the event of a farm out we will keep a piece of farm out both of this, and that would free up funds to accelerate our activity in South Texas Neptune. Joel Musante – CK Cooper & Company: Okay, sounds good, thanks.

Thank you (Operator instructions). Our next question comes from the line of Dick Feldman with Monarch Capital. Please go ahead. Dick Feldman – Monarch Capital: Good morning, guys.

Hi, Dick. Dick Feldman – Monarch Capital: You mentioned that you intend to bring two wells on Neptune. Can you give us any guidance as to what type of production rates we should be expecting there?

Dick, I only got about half of that. Could you repeat the question please? Dick Feldman – Monarch Capital: I am looking for what are the initial production rates from the two wells you are bringing on at Neptune.

Okay, the reserve report that we have from engineer projected a 10 barrel a day rate. Initial rate, obviously, very slow decline, long way. And still we actually get a well online in (inaudible) I can’t really give you anything different from that. Hopefully, we’ll do better, but certainly, if we can do that, well, then that still gives us a good project for us. Dick Feldman – Monarch Capital: So if you were to realize those types of production rates you would consider bringing on other locations?

See, the development plan in our expectations are built upon our reserve report which is that 10 barrel a day rate, 29,000 gross barrels, about 23,000 net barrels per well, which is about a $11 per barrel cost, which is extremely attractive when oil selling from north of $70 a barrel plus fact that the oil is a gifted premium price because of its location and gravity, so, yes, 10 barrels a day that still would generate for all of our locations about a $40 million PV 10 to extrapolate it down from the current reserve report. That’s an imminently possible project even at that rate. Dick Feldman – Monarch Capital: I want to switch to the artificial lift technology. You said the first two locations look successful so far. Since these are wells that are largely played out, is there a lot of reserves to be covered in aggregate or is this by its very nature remain a sort of niche type of product?

Obviously, that is what we’re trying to prove that it is not a niche project, it is a technology, and it has applications and any horizontal well that has liquid production. That liquid loads up your pump, intervene gas production, gas loading which prevent oil production and once those pressure drops, the reservoir and liquid level drop about with a rod pump is, you no longer able to get any more fluid out hole. We believe that it is viable for recovering an extra 10% to 15% of reserves. The better the well the better the results with this technology we believe. The fact is that our first test location that we did that had good results on and appear to be that is substantial reserves is on a well that was a horrible well from day one. It was not a good well, of course, is our first well in oil, so you would expect therefore to get the worst results with this technology and the fact is it the technology has generated a very commercial well for us, right now. What we consider to be a dock well. So we think it is that wide application, but we are still in that process of proving that. Dick Feldman – Monarch Capital: Okay. I will get at the end of the queue. Thank you

Thank you. (Operator instructions). Our next question comes from the line of Robert Kecseg with Las Colinas Capital Management. Please go ahead. Robert Kecseg – Las Colinas Capital Management: Hi, Bob.

Hi. Robert Kecseg – Las Colinas Capital Management: I just wanted to ask a question on that artificial lift also. Could you kind of speak to what you know differently now about the utility of it is as far as whether its cost prohibitive or you can go down, you are talking about really poor well, is there a different amount of knowledge that you have about, how is working now with a little bit (inaudible).

Sure, I really got, that’s your question – Robert Kecseg – Las Colinas Capital Management: I’m wondering is, is other cases of lot of wells that could be applied to is there a cost prohibitive factors where well producing still a little bit, it isn’t really worth of cost to do it?

Obviously, there’s always going to be a spectrum of result, in some wells, won’t do well, for whatever reason, the process itself cost about a 150,000 or so, since fall, so, on that basis that works out to, if we say, that a BOE in the ground is in a sharp for example, the Giddings Field, as a value of say, $25 per BOE, then you had on your royalty and so forth, what that suggest is that you need, is that about 8,000 BOE growth you pay for the process. That is not really all that much production out of these wells that that have made 100s of 1000s of barrels and we’re trying to get an extra 10% to 15% recovery. So, our goal in Giddings Field is a recovery of anywhere from 20,000 BOE to 50,000 BOE growth. So we think across the board it’s going to be quite economic for operators to deploy this. Not every well, obviously, will be a candidate. Some wells are too small, casing, some wells are too dry, some wells, they’ll be at a really, really short radio fix on to it. The amount of main pressure may not be sufficient to generate economic reserves. So we think that by and large, it will be applicable to a large number of wells, in a Giddings Field it’s been over 10,000 wells drilled. Obviously, that’s a huge target for us to within that one field. And then our next goal is to demonstrate and help shale well, which widens the universe even further. Robert Kecseg – Las Colinas Capital Management: Okay, thank you.

Thank you. (Operator instructions). And Mr. Herlin, there are no further questions in the queue. Please continue.

Okay, well, again, that’s thanks to everyone for joining us this morning and if you have further questions feel free to call, then we will tell you everything we can within the public domain. With that, I thank you and look forward to our next quarterly review.

Ladies and gentlemen, this concludes the Evolution Petroleum second quarter of fiscal 2010 earning call. If you would like to listen to a replay of today’s conference, please dial 303-590-3030 with the access code of 4220160. ACT would like to thank you for your participation. You may now disconnect.