US Energy Corp (USEG) 2014 Q1 法說會逐字稿

Good morning. My name is Danielle and I will be your conference operator today. At this time I would like to welcome everyone to the U.S. Energy Corp. first-quarter 2014 selected highlights, financial results and operations update conference call. (Operator Instructions) I would now like to turn the call over to Mr. Reg Larsen, Director of Investor Relations of U.S. Energy Corp. Sir, you may begin your conference.

Thank you. Good morning, ladies and gentlemen, and thank you for joining us today. With me this morning is Keith Larsen, Chief Executive Officer of the Company; Steve Richmond, the Company's Chief Financial Officer, as well as members of the Company's management team. In terms of agenda for the call, Keith will provide you with an overview of our highlights, financial results and operating initiatives for the quarter ended March 31, 2014, as well as the period subsequent to the quarter end, and we'll finish the call with a question-and-answer session.

As a preliminary matter, I would like to note that during this call we may make forward-looking statements which may be identified by the words will, anticipate, expect, and similar words that are based on these beliefs and assumptions of U.S. Energy's management. These and all statements, other than statements of historical fact, are forward-looking statements within the meaning of Section 21E of the Securities and Exchange Commission Act of 1934 and Section 27A of the Securities Act of 1933.

The forward-looking statements are subject to numerous risks and uncertainties, including those described in the form 10-Q for the quarter ended March 31, 2014, which we filed on Friday, May 9, 2014, and our other filings with the SEC, all of which are incorporated herein by reference. Relevant non-GAAP reconciliations are available on the Company's website which is located at www.USNRG.com. I would now like to turn the call over to Keith.

Thank you, Reg. To begin today's call, I would first like to thank the audience for attending our conference call and for following the Company's progress during the first 3 months of 2014, which have been active on several fronts.

During the 3 months ended March 31, 2014, the Company produced 105,093 barrels of oil equivalent, which is an average of 1168 net BOE per day. This production comes from 123 gross, or 17.5 net wells, primarily located in the Williston Basin of North Dakota and South Texas.

As a result, the Company recognized $8.3 million in revenues during the quarter, as compared to $7.9 million during the same period of the prior year. The $377,000 increase is primarily due to higher oil and gas sales volumes when compared to the same period of the prior year.

During the quarter, we recorded net income after taxes of $250,000, or $0.01 per share, basic and diluted. Looking ahead, we remain in a good position to fund our forward drilling programs. At March 31, 2014, we had $2.5 million in cash and cash equivalents. An additional $14 million in borrowing capacity under our $25 million line of credit with Wells Fargo.

Subsequent to the quarter end, we have drawn down an additional $6 million to fund an 800 gross, 60 net acre AMI election and acreage immediately adjoining the Booth Tortuga acreage block as well as our recently announced 12,100 gross acre Dimmit County acquisition. This draw leaves our remaining borrowing capacity at $8 million currently. We anticipate adding an additional $1.5 million of capacity, based on our year-end reserve report during our semiannual redetermination which is anticipated to be finalized this week.

During the quarter, we received an average of $2.8 million per month from our producing wells with an average operating cost of $417,000 per month, including work over costs and production taxes of $241,000, for average net cash flows $2.1 million per month from oil and gas production before non-cash depletion expense.

In the financial and operational release that was published on Friday, May 9, which is available on our website, we presented an EBITDAX table showing earnings before interest, income tax, depreciation, depletion and amortization, accretion of discount on asset retirement obligations, non-cash impairments, unrealized derivative gains and losses and non-cash stock compensation expense, which we refer to as Modified EBITDAX and a reconciliation of Modified EBITDAX to net income. Modified EBITDAX was $4.1 million for the quarter ending March 31, 2014.

Now moving on to our oil and gas operations, our primary focus remains on our active drilling programs in South Texas, targeting the development of the Buda Limestone formation in Zavala and Dimmit Counties and on our drilling programs and several operators in the Williston Basin.

In South Texas, and the Company now participates in approximately 34,500 gross, 9000 net acres in Zavala and Dimmit Counties, a 58% increase in net acreage as compared to year and 2013. As previously mentioned, the increased figures come through an AMI election of an additional 800 gross or 60 net acres immediately adjoining the Booth Tortuga acreage block as well as our recently announced 12,100 gross, 3384 net acres Dimmit County acquisition.

In the Booth Tortuga acreage block, located in both the Zavala and Dimmit Counties Texas, the Company has an approximate 30% working interest and an approximate 22.5% net revenue interest and approximately 13,114 gross or 3561 net acres. A full-time rig is contracted to drill wells in succession during the balance of 2014, contingent upon continued success in the program.

During the quarter, we completed the drilling of the number 6, number 7 and number 8 wells. The Beeler number 6 well had an initial production rate of 1185 gross BOE per day. That was 91% oil, and the 30 day average production rate of 778 gross BOE per day. The Beeler number 7 well had an initial production rate of 440 gross BOE per day, 90% oil and a 30 day average production rate of 187 gross BOE per day. Beeler number 8 well had an initial production rate of 886 gross BOE per day, and again, 91% oil and a 30 day average production rate of 347 gross BOE per day.

Subsequent to the quarter's end, Contango completed the Beeler number 5 and the Beeler number 9 wells. Both wells commenced production in late April and initial flow rates are currently being monitored. As this program has now matured from the initial testing stage with 9 gross wells drilled to date, we have made an election to only publish production rates once 30 days of data has been evaluated. We believe this is a more accurate measure of an individual well's production profile and is a more meaningful data point for investors.

The Beeler number 16 well was spud on April 18, 2014. The well was drilled to a vertical depth of approximately 7000 feet with an approximate 4000 foot lateral. Upon the completion of the drilling of the first lateral, the operator elected to come back to the heel of the well and sidetrack and drill an additional approximate 4000 foot lateral. Both laterals are currently being completed naturally without fracture stimulation.

Beeler number 17 well, which is located directly to the south of the Beeler number 16 well is scheduled to spud this week. The Beeler number 10 and Beeler number 20 wells are anticipated to be spud in early June and late June, respectively.

On May 7, 2014, under an Area of Mutual Interest Election, the Company acquired a 7.5% working interest in an additional 800 gross, 60 net acres in the Booth Tortuga prospect. This acreage is offered through and is operated by a private, Texas-based Company. The first well to be drilled on the acreage, the Bruce Weaver #2 well will target the Buda formation and is scheduled to spud in late May. The acreage block lies between the Beeler number 16 and the Beeler number 9 well locations.

Now moving on to our Big Wells prospect, which is contiguous to the southwestern portion of the Booth Tortuga acreage block. The Company has a 15% working interest, 11.25% NRI, and 4243 gross or 636 net acres from U.S. Enercorp, a private oil and gas Company based in San Antonio, Texas.

The second Buda formation well on this acreage, the Williston number 2 well will spud in early February 2014. The well was completed open hole, without fracture stimulation and commenced production the first week of March. The well had an initial production rate of 634 gross BOE per day and that was 72% oil and had a 30 day average production rate of 179 gross barrels of oil equivalent per day. The operator plans to monitor the production from both wells in the acreage block before additional development plans are made.

I will now move on to our Dimmit County acquisition, which was announced via press release on Thursday, May 8. Under the agreement, the Company acquired 33% of the seller's interest in approximately 12,100 gross or 3384 net acres. The acreage consists of primary leasehold acreage and farm-in acreage to be earned through a continuous drilling program. The farm-in acreage initial 2 well commitment and a 12.5% working interest carry for the farmer in the first 10 wells.

After 100% payout of all cost for the first 10 wells that are drilled under the farm-in program, the farmer will back into its 12.5% retained working interest in the prospect. The seller also retained a 25% working interest back in after 115% of project payout has been received by the Company. The Company paid $3.9 million to enter into the transaction, which includes leasehold and farm-in acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

A minimum of 3 Buda formation wells are scheduled to be drilled during the balance of 2014. The first well in the program spud the week of May 5 and is currently drilling in the vertical portion of the well bore. As additional leasing and farm-in opportunities are still being pursued, we do not plan to identify the location of the prospect or the wells by name until drilling results and additional leasing results warrant further disclosure.

In summary, we continue to refine our focus on this region in South Texas due to the potential of the Buda formation as well as the additional multiple stack hydrocarbon bearing formations that are present. In addition, down spacing and fracture stimulation of the Buda formation and other formation development in each prospect may enhance the oil and gas reserve potential.

Now I will move on to the Williston Basin of North Dakota. We participate in 65 1280-acre spacing units in the basin with numerous operators. At quarter's end, we had 97 drills, 10.6 net producing wells and 13 gross 0.22 net wells being drilled or awaiting completion. Subsequent to the quarters and, four of the gross wells that were pending completion at quarter's end are now producing, and three gross wells are currently being completed to be turned over to production.

During the three months ended March 31, 2014, we averaged approximately 679 net BOE per day from this segment of our business, which was negatively impacted by winter weather related issues in the basin during the quarter. We are now beginning to see improvement in this area as we enter into the spring months and things begin to flow better from an operational standpoint. We continue to actively participate in the drilling and completion of our inventory of wells in the basin in order to maintain our base production from this region.

To close out the operations portion of the call, I would also like to mention how the Company deploys a risk management strategy covering our oil and gas production through its hedging program. Currently, we have hedged 600 barrels of oil per day through 2014 using costless collars. The weighted average floor price for the second through fourth quarters of 2014 is $90 per barrel and our weighted average ceiling price is $97.31.

Before moving on to the question and answer portion of today's call, I would also like to highlight a few additional points of progress which had been made early in 2014. While we continue to develop our portfolio of assets in North Dakota with our partners, we have also refined our focus on acquiring and developing oil and gas assets in South Texas and we believe that this area will continue to be a growth catalyst for the Company and its shareholders in both the short and long-term.

We continue to evaluate our production field data and we're learning more from a regional perspective on a daily basis. With this information in hand, we elected into an additional parcel through an AMI election last week and also announced our Dimmit County acquisition, which we believe has a high probability of success based upon our technical evaluation of the acreage.

With these recent developments, we expect to have three rigs drilling by late May, targeting the Buda formation. I would also emphasize the multiple stack pay nature of this area as we believe that there is a potential for additional development on a going forward basis.

Additionally, we recently hired a full-time land man with 8 years of experience in leasing in South Texas. He has spent the last 4 years actively leasing and developing both industry and private relationships in our target areas in and around Zavala and Dimmit Counties. We plan to fully utilize his understanding of this area to continue to grow our acreage and development portfolio.

That being said, we will continue to manage our balance sheet and drilling commitments with a goal of increasing production, reserves, revenue and cash flow from operations with the ultimate goal of driving growth and profitability for the Company's shareholders.

Finally, I would like to mention that we've identified the top 20 producing counties in the US, which account for 52% of all oil production and 20% of all gas production. U.S. Energy is significantly involved in the number 5-ranked County, McKenzie in North Dakota, the number 6-ranked County, Mountrail in North Dakota, the number 12-ranked County, Williams in North Dakota and, finally, the number 14-ranked County, and that is Dimmit in Texas.

We believe we can expand our presence in these areas and our focus will be geared toward these areas as we strive to add to our production profile and reserves. That concludes our prepared remarks for today. Operator, would you begin the Q&A session now, please?

(Operator Instructions) Noel Parks, Ladenburg Thalmann

Good morning. Can you hear me?

Yes, good morning, Noel.

Say, I was just curious, what are you thinking of in -- as far as alternate or deeper formations in East Texas at this point? That has really been expanding the drilling inventories, so I was just wondering if it is going to be essentially just Buda from here on or if you are thinking about in the near-term the operators targeting some other formations?

Noel, as you could imagine, we're getting logs of several formations as we are going down to the Buda, and as well, the Georgetown sits directly below the Buda, but we've got the Eagle Ford potential, the Austin Chalk, the Edwards, and all of those are being analyzed and look like -- looked at as we are drilling the Buda.

We are getting some gas kicks and getting some interesting data, I suppose, would be the best way to put it right now, but in the immediate short-term, it is basically the Buda, and then if we get some interesting looks, then our operators have indicated that they are open to going out and testing some of these other formations.

Okay. You described one of the wells where one lateral was drilled and then the operator went back and I guess in the opposite direction and did an additional lateral. Is that a practical way to look at the development going forward or was that just the situation that you had a particular lease that accommodated that?

My understanding is that was pretty common practice in the Austin Chalk and they had pretty good results. Of course, if we get a very well performing well, it would be very highly probable the operators would do a two lateral in the future, and by the way, Noel, it is not in the opposite direction, it is parallel to the first well.

Oh, the same direction, but just deeper in the formation, or --?

It is about the same depth. Our operator is Contango on this particular well, believes they know the gamma signature and that is what they follow and basically it is about 20 foot off the bottom of the Buda.

I see, great. And just at this point, with the various farm-in agreements and so forth you are looking at, do you have a sense on a net basis looking ahead the next year or two, roughly where the budget might head or are we looking at maybe 50% higher going forward if you continue on this track, or --?

Certainly those are the goals that we are shooting for, Noel. We don't give guidance on what our production is because of the nature of being a non-operator as well as the early nature of being in the Buda. But certainly our goals here at the Company is to increase our production by 50% for the year and to leave the year significantly higher than that on a daily basis.

Great. That's all for me.

Okay. Thank you, Noel.

Thank you.

Evan Richert, Sidoti & Company

Morning, guys. Noel had asked a couple of my questions. I was just wondering -- I guess to start off, your thoughts on production rates so far. I know you are bringing on a third rig in Texas now but would you have expected any more contribution out of Booth Tortuga and Buda, or is this kind of in line with what you were hoping for?

Well, not quite in line. We thought that we would have some more of our better performing wells, although the wells that we have, the numbers speak for themselves. It is just going to be, I believe, a statistical play down there. We are going to have some better wells and some that are kind of mediocre, if you will, as well as we were a bit disappointed, but not that surprised with the slowdown up in North Dakota in the Bakken wells because of the weather up there and the nature of North Dakota in the wintertime.

Sure. On that note, what kind of drilling times were you seeing up there during the quarter in the Bakken?

I think they've got it down to about 21 to 25 days.

So that wasn't --? I guess I am just trying to assess the weather impact.

Yes, you know, the drilling wasn't impacted as much as the completion.

Okay.

As well as they shut several wells in because of flooding, and they -- as you are probably aware of -- and they also had road closures in the spring --.

Sure.

(multiple speakers) the roads in those type of things. I think you have pretty much seen it across-the-board with most Bakken players up there. They have had a decrease of some 15% to 30% decrease in their production.

Okay, and then just to clarify one thing Noel asked on -- I think it was the 16H that you had the other sidetrack on, that was because you were -- the operator was pleased with the results, not because of a mechanical issue?

No, it was because they were pleased with the results and because of the speed in which we drove the first lateral. They are getting better at it, if you will.

Okay.

I would anticipate in the future that we probably will continue this practice, especially if we have the type of level we think we have.

Okay, that's helpful. Then, now that you are bringing on a third rig, I know you had the CapEx budget set. Do you have kind of a number in mind on how much you would expect to go to drilling versus acquisitions for the year?

Pretty much I think that most of our money is going to go towards drilling now.

Okay, so now that the recent acquisition is in, you're just focused on drilling with the remainder of the budget?

Pretty much for this year we are just focused on the drilling.

Okay. Then the AMI you talked on that I think you said hit last week, did any cash change hands on that?

Yes, there was about $300,000.

Oh,just $300,000. Okay. That's it for me. I will hop back in the queue.

Okay. Thanks, Evan.

George Gaspar, Private Investor

Yes, good morning. First question is regarding, again, the Buda drilling process. Could you highlight the drilling costs on a per well basis that you are encountering currently versus where you were initially? Can you highlight also when a lateral is drilled, what is the additional cost to do that lateral versus the initial penetration horizontal?

Sure, well, your first question was how are the costs looking and we are very pleased with Contango especially. The first initial costs were around $4 million to $4.5 million; they've got it down closer to around $3 million for completing the (technical difficulty) drilling and I think it is split about evenly. Steve, do you got a -- about $1.5 million to drill, and about $1.5 million to drill the lateral.

So, what you are saying is $1.5 million to drill the vertical portion and $1.5 million to drill the lateral?

And complete.

And complete? Okay. Then the question is ongoing, when you drill a second lateral, what kind of cost does that incur in terms of the well costs since you are already down vertical, just moving over and drilling a second horizontal?

George, I don't want to give you a number that I don't know. I will have to look into that. If you want to give me a call afterwards, I can talk to you about it, but I don't know right now.

Okay. I know that you answered this in part earlier to a question. Regarding lateral drilling, you've implied that the laterals are near parallel so you're not getting out very far, broadening the endpoint. How close can you get together between laterals and the existing -- the initial drilling so that it doesn't cause pressurization changes in the structure because you are drilling open hole?

Again, I don't have the complete answer to that, but my recollection is the endpoints, or where they land that second lateral is about 1500 foot away from the first lateral. Of course, in the beginning, it is going to be very close to the first lateral.

Okay. Okay, so it would be up to something like 1500 feet away at the endpoint?

That is my recollection, George.

Got you. Okay. All right. Can you, Keith, regarding the whole area that you are in out there in Dimmit, particularly, and you have been able to correlate additional acquisitions of opportunity there. What is happening in terms of other companies in the area? Can you identify that -- is this area becoming more attractive to other drillers and how close in or can you continue to expand your area of opportunity?

I believe that we can expand it, but to answer your question, I think there is more interest, not only because of us, but others that have had success in the Buda and that is why we are being a little bit close to the vest with this acquisition. We believe there are additional opportunities and we certainly don't want to drive the prices up.

Okay, all right. One, if I could, one question on North Dakota. This peeling off in the first quarter I assume was because of givebacks on where wells had neared their total cost outlays and the giveback was incurred or the decline curves now. You've got a lot of small interest in a lot of wells that are drilling. Do you think that you can stabilize your current production by the type of drilling you are doing now, or potentially even increase the production per day? What is your thought on that?

What our thoughts are initially and internally is that we plan on maintaining our base production, not growing it. The additional drilling, because of the smaller nature, will stabilize that production. A lot of the wells that we have interest in now are older wells and so the decline profile is much, much lower than the initial wells. But of course, we rely on the flush production from the smaller interest wells to maintain that production base as well, so the answer to the question is, to maintain that production of around 700 to 800 barrels per day.

Okay, all right. Thank you.

(Operator Instructions) Mike Jacobson, Oak Ridge Financial.

Good morning, gentlemen. Wonder if you can give us an update, maybe including timetables regarding the Mt. Evans project?

Sure, Patrick. This is Mark Larsen.

Michael.

Or Michael -- we have continued forward with our permitting. We are evaluating our next steps there, and, of course, perfecting our water rights along the way. We have also looked at ways to reduce the cost of the holding cost of the water treatment plant and the water that we treat from the Keystone mine, and at the same time, we have kept open discussions or the opportunity for discussions with the town parties for various alternatives on how to monetize that asset. So we are keeping those three activities active and ongoing.

Okay. What is the next step in the permitting process? Or is that all set and ready to go now?

The next step is to go out and do a water background study and to do that study we have to enter into an EIS. It appears we are still negotiating that with the forest service and the time it will take regarding the scope of work that will be entailed in that process, that's -- that type of decision is going to be made in the next, I would say, 90 days. That work could begin within that timeframe, as well as continuing the permitting process itself and other items that are -- it is a several faceted project, as you could imagine, so we are monitoring each of the moving parts, literally on a daily and weekly basis. We are in contact with the forest service, our consultants in various agencies frequently.

(multiple speakers) Michael, to answer your question, the bulk of the work on the permitting will not start until next year because of the EIS and the scoping that Mark mentioned.

Yes, so it is a year or two away yet?

It is.

Thanks.

Okay. Thank you, Mike.

Patrick Rigamer, Global Hunter Securities.

Good morning, guys. Just with the shift in focus to the Buda just curious if you have an ultimate acreage goal or a yearend target on how many acres you would like to have there?

I think pretty much what we've got right now. We need to drill and get results, Pat, and see what we have.

Okay. Then in your presentation you show some pretty impressive economics for the Buda and that is at the $4 million well cost per just curious if you had run that analysis at some of these lower-cost that we have been seeing in the $3 million range?

We haven't, but before our next presentation, we will have those numbers included and probably some averages so that we have more history now so we know exactly what the EURs in the production profile are for a group of wells and we can be more accurate in our economics.

Okay. Well thank you very much.

Thank you, Patrick.

George Gaspar, Private Investor

Thank you. Keith, relative to what you targeted for drilling costs for 2014, can you share with us where you might see that total number being for the year now relative to your accomplishments of some additional acreage plays involved that you have taken down?

I think we had $12 million budgeted for the Texas acreage and that probably will be bumped up somewhere closer to $15 million, $16 million for the year, total.

Okay. All right. So then for the year in total, if it gets to $15 million in the Buda area, what do you envision for the year then in total?

In total, somewhere around $35 million.

$35 million? Okay. Are you generating -- do you have the capacity right now to generate about $2 million a month in terms of cash flow that is going back into the drilling?

That is what we generated for the first 3 months, George; it was a little over $2 million. I think it was $2.1 million.

On a per month basis?

Per month and as we increase our production profile, with the success, hopefully success that we are doing down there we expect that to increase and we will exit the year at somewhat higher than that.

I see. Okay. Well, that's good. Then, on the -- you mentioned -- you made reference to being interested going forward in some potentially deeper levels below the Buda. Is there any -- been able to track any other exploration companies in the general vicinity of the Buda on drilling projects that are going deeper that maybe have taken place more current than in past years? Do you have any fix on that at all?

No, the lower formation that I have seen people targeting down there is the first salt and it is quite significantly deeper, somewhere around 10,000 foot and there has been mixed results there, but we are more interested in possibly the Georgetown, which is directly beneath the Buda.

Great.

And the Edwards, which is significantly above the Austin Chalk.

Okay, all right. Thank you.

Thank you, George.

Thank you. There are no further questions at this time. This concludes today's conference call. You may now disconnect.