Evolution Petroleum Corp (EPM) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Evolution Petroleum's 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, February 16, 2010.

I would now like to turn the conference over to Lisa Elliott of DRG&E.

Thank you, Luke, 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 do have a few items to go 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 website and that's at www.evolutionpetroleum.com or via a 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.

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 a discussion of probable and possible reserves or use terms like volumes, reserve potential or recoverable reserves. The SEC generally only allows disclosure of proved reserves on security filings and these estimates of non-proved reserves or resources by their very nature are more speculative than estimates of proved resources 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, and good morning to everyone. Thanks for joining us today. Sterling McDonald will be here or 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 into any detail review of the numbers but we will take questions that 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 injection began in mid-November in the Delhi Field in Northeast Louisiana. Denbury continues to roll out that project and is now in Phase 2. We still believe that first oil production response will occur some time by mid-calendar 2010.

Although our 25% reversionary interest won't likely kick in for a few years, we are going to be receiving revenue from the project through the initial production and the initial production response through our 7.5% [growth] interest throughout the life of the project. We expect production to ramp up as injections extended throughout the field and to be meaningful to us as early as this summer.

We also expect initial production response from the CO2 injection to support a reclassification of a significant portion of our probable reserves to proved categories.

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 tests that will hopefully position us for reserve upgrades as well as generate additional revenue. We are maintaining a conservative expenditure program until higher cash flows in the future support a more aggressive plan.

We believe that our best use of capital now is to prove the commerciality of our projects and to delineate the potential for development. In the Neptune Project's 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 reentry of existing wells. We should have this done sometime in the next couple of weeks weather permitting.

We also have been working on expanding the number of potential infill locations and now have that number up to about 112 sites identified which is obviously subject to the success of the first two producers.

In the Giddings Field, we are currently focusing on maintaining our production as much as possible and controlling our costs with the objective of covering our total overhead expenses. We currently have 10 wells on production in the field -- we have nine wells on production in the field with the tenth well about to be put back on production after some repair work.

During the latest 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 in the prior quarter. Although these wells are past their stage of steep decline, volumes were negatively impacted during the last quarter by a continued suspected blockage within the lateral section of our Hilton-Yegua well; downtime in the Pearson well for tubing, plugging and downstream compressor repair; and downtime on our Williams well for installation of our artificial lift technology; and compressor work on the [Denoa], which is the first well we installed GARP on.

The plug in the Pearson tubing has been cleaned out and it rate went back to its previous 1.2 million cubic feet equivalent per day rate in January. Denoa has been off-line since late December waiting on parts of the compressor but we should have that back on production shortly.

For the balance of the fiscal year, we plan to conduct a lateral clean out of that Hilton-Yegua well for that special plugging. Our capital plan does not yet include the drilling of any new wells in Giddings, but we are actively working on potential joint ventures to accelerate that development drilling.

[Chief] operating costs, including production taxes in the Giddings Field, were up about 13% just on $12.37 per BOE, which is primarily due to the 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 well for the Pearson. We put that on in the middle of the last quarter to lower water handling cost.

Including our depletion rate of some $17.25 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 a second well, the Williams, during normal work over. We believe that the combination of that technology plus the normal installation of a rock pump has substantially enhanced this production as well as backed up to about 160 Mcfe per day. We are also in early stage discussions with third parties to potentially apply that technology to their marginal, uneconomic or shut-in 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 shales. We are pleased that the Caney shale well is testing favorably so far and is consistently producing water at a steady 25 Mcf a day rate which we believe confirms that if the Caney can contribute commercial gas volumes 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 rates but the test production is on hold while we deepen the associated water disposal well to handle the water.

Now that work is underway and we expect to have that well back in test production shortly. Again, weather permitting.

The goal of Oklahoman is to determine to eke initial production rates and decline profiles. 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 4000 feet to 5000 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 to $1.25 range per Mcf which appears to be attractive in the current gas price environment.

Now after these operating results, I will turn the call over to Sterling to talk about more of the numbers.

Thanks, Bob, and thanks to all of you for joining us today. Since we filed our 10-Q last Friday and assuming that you've either reviewed it or the earnings release we put out this morning, I'll just hit a few highlights and give a sense of what we are expecting for the balance of the fiscal year.

On the cost side, we expect operating costs, G&A, and DD&A rates to stay in line with our second quarter. As to G&A, we should be able to maintain the absolute levels we've recently achieved through our recent 25% year-over-year reduction in G&A.

As for lease operating expenses, we may be able to slightly improve our 6% year-over-year decline per barrel of oil equivalent since the new saltwater disposal well that Bob mentioned for the Pearson was not online for the first full first fiscal quarter.

As you may recall, we expended about $425,000 to complete a saltwater disposal well at the Pearson to avoid about something more than $30,000 of monthly water hauling expense. On the margin, this reduced lifting costs of over $6 a BOE on a substantial part of our production at current rates 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 $1 million per quarter in our oil and gas properties. Year-to-date, 95% of our oil and gas expenditures have been for development. Of those, 60% were at Giddings, 28% at Neptune, and 32% in our shallow shale property in Wagener Oklahoma.

On liquidity, we continue to be debt free while cash flow from operations was positive during the second quarter coming in at $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 assets. With the Delhi Project projected to begin generating cash flow in about three 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 could provide further flexibility and opportunity for growth.

That completes my comments. I'll turn the call back to Bob.

Thanks, Sterling, and now will be happy to take any questions -- well, most any questions you are willing to (inaudible).

(Operator Instructions) Joel Musante, C.K. Cooper & Co.

Hi, Bob; hi, Sterling. 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 the JV goes?

We are looking at a wide range of options. We will consider any number of possibilities ranging from the sale of the whole thing to a farm out of the whole thing to a farm out of selected locations. We are wide open to how we can accelerate that program and allow us to accelerate then our other projects.

We feel at the moment with where oil and gas prices are that these locations are now eminently attractive and so far, we have been pleased with the reception by industry.

Okay. All right. So you would potentially take -- you would potentially monetize this to invest in Neptune or the Woodford project?

Well, certainly is a possibility. I suspect that in the event of a farm out, we would keep a piece of it, farm out the bulk of it and then that would free up funds to accelerate our activity in South Texas and Oklahoma.

Okay, well, that sounds good. Thanks.

(Operator Instructions) Dick Feldman, Monarch Capital.

Good morning guys. You mentioned that you intend to bring two wells on at Neptune. Could you give us any guidance as to what type of production rates we should be expecting there?

Dick, I only got about half that. Could you repeat that question please?

I'm 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 barrel a day rate, initial rate with obviously very slow decline long life. Until we actually get a well on line and see it, I can't really give you anything different from that. Hopefully, we will do better but certainly if we can do that well then that's still a good project for us.

So if you were to realize those types of production rates, you would consider bringing on other locations?

Yes. We have -- the development plan and our expectations are built upon again our reserve report which is at that 10 barrel a day rate, 29,000 gross barrels, about 23,000 net barrels per well which is about $11 per barrel cost which is extremely attractive when oil is selling for north $70 a barrel. Plus the fact that oil gets a premium price because of its location and gravity.

So yes, at 10 barrels a day, that still would generate for all of our locations about a $40 million PV-10 if you extrapolated it out from the current reserve report. So that's an eminently profitable project even at that rate.

I want to switch to the artificial lift technology. You said the first two applications look successful so far. Since these are wells that are largely played out, is there a lot of reserves to be recovered in aggregate or is this by its very nature remain a sort of niche type of product?

Well, obviously that is what we are trying to prove that it's not a niche project, it is a technology that has application in any horizontal well that has a liquid production. Because that liquid loads up your pump and prevents gas production which prevents -- you have gas loading which prevents oil production and once the pressure drops in reservoir, your liquid level drops to about where that rod pump is, we no longer are able to get any more fluid out of the 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 we had good results on and appeared to be -- have added substantial reserves is on a well that was a horrible well from day one. Not from day one -- it was not a good well for us. It is our poorest well on the portfolio.

So you would expect therefore to get the worst results with this technology and the fact is the technology has generated a very commercial well for us right now on what was what we consider to be a dog well. So we think it has got wide application but we are still in that process of proving that.

Okay. I will get at the end of the queue. Thank you.

(Operator Instructions) 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 as far as whether it is cost prohibitive or you can go down? You are talking about a really poor well. Is there a different amount of knowledge that you have about how it's working now with the little bit that you have able to apply it?

I'm not sure I really got -- got your question.

What I'm wondering is are there cases of a lot of wells that it could be applied to? Is there a cost prohibitive factor to where the well produces so little that isn't really worth the cost to do it?

Well obviously there's always going to be a spectrum of results and some walls won't do well for whatever reason. The process itself costs about $150,000 or so to install. So on that basis, that works out to -- if you say that a barrel of oil in the ground -- a BOE in the ground is in the Chalk for example, the Giddings Field has a value of say $25 per BOE. Then you add on your royalty and so forth, what that suggests is that you need -- what is that -- about 8000 BOE gross to pay for the process. That is not really all that much production out of these wells that have made hundreds of thousands of barrels. And we are trying to get an extra 10% to 15% recovery.

So our goal in the Giddings Field is recovery of anywhere from 20,000 to 50,000 BOE gross. So we think across the board, it's going to be quite economic for our operators to deploy this. But not every well obviously will be a candidate. Some wells have too small a casing. Some wells are too dry. Some wells that may be on the really, really short radio component to it, the amount of remaining pressure may not be sufficient to generate economic reserves.

But we think that by and large it will be applicable to a large number of wells. In the Giddings Field, there has been over 10,000 wells drilled. Obviously, that's a huge target for us just within that one field. And then our next goal is to demonstrate the [helps] and shale wells which widens the universe even further.

Okay, thank you.

(Operator Instructions) Mr. Herlin, there are no further questions in the queue. Please continue.

Okay, well, again, thanks to everyone for joining us this morning and if you have further questions, feel free to call us and we will tell you everything we can that's in the public domain.

With that, I thank you and look forward to our next discussion and our next quarterly review. Good morning.

Ladies and gentlemen, this concludes the Evolution Petroleum's 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 4220160.

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