US Energy Corp (USEG) 2014 Q2 法說會逐字稿

Good morning. My name is Kate and I will be your conference operator today. At this time I would like to welcome everyone to the U.S. Energy Corp. second-quarter 2014 selected highlights, financial results, and operations update conference call. (Operator Instructions)

I would now like to turn the conference 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 management.

In terms of an agenda for the call, Keith will provide you with an overview of our highlights, financial results, and operating initiatives for the quarter ended June 30, 2014, as well as the period subsequent to quarter end. And we will 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 the beliefs and assumptions of U.S. Energy's management. These and all statements other than statements of historical fact are forward-looking statements in the meaning of Section 21E of the Securities and Exchange 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 June 30, 2014, which we filed yesterday, 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.

Thanks, Reg, and welcome, everybody. I would first like to thank the audience for attending today's call and for following the Company's progress through the midyear point of 2014.

To begin, I am pleased to announce that the Company has recorded net income after taxes of $56,000 during the quarter ended June 30, 2014. During the six months ended June 30, the Company recorded net income after taxes of $306,000, or $0.01 per share. During the three months ended June 30, the Company produced 116,499 barrels of oil equivalent, which is a 15.3% increase over the same period of 2013 and a 10.9% increase over the first quarter of 2014.

Average net daily production was 1,280 barrels of oil equivalent during the quarter ended June 30 and I would like to note that June's monthly average daily production was up to 1,352 net barrels of oil equivalent per day. The uptick in production comes primarily as a result of the Beeler Number 16 and 17 wells in South Texas, which began producing mid-June. Overall, our production revenues come from 117 gross, 18.1 net wells primarily located in the Williston Basin of North Dakota and in South Texas.

As a result of our production growth, the Company recognized $9.1 million in revenues during the second quarter of 2014, which is a 15.3% increase as compared to $7.9 million during the same period of the prior year. For the six months ended June 30, the Company recognized $17.4 million in revenues, which is a 10.1% increase in revenues as compared to $15.8 million in revenue during the same period in 2013. Both increases are primarily due to higher oil and gas prices and higher oil and gas sales volumes when compared to the same period of the prior year.

Looking ahead, we remain in a good position to fund our forward drilling programs. At June 30 we had $4.3 million in cash and cash equivalents and an additional $16.5 million in borrowing capacity under our $24.5 million line of credit with Wells Fargo. During the quarter, our borrowing base was reduced from $26.5 million to $24.5 million, due to the divestiture of certain assets and associated reserves in the Williston basin of North Dakota for $12.2 million. Subsequent to the sale, $9 million of the proceeds were used to pay down the credit facility, resulting in a remaining balance of $8 million.

During the six months ended June 30, we received an average of $2.9 million per month from our producing wells with an average operating cost of $510,000 per month including workover costs and production taxes of $250,000 for average net cash flows of $2.1 million per month from oil and gas production before non-cash depletion expense.

In the financial and operational release that was published yesterday, 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 $4.2 million for the three months ended June 30, an increase of 12.5% when compared to a modified EBITDAX of $3.8 million for the same period of 2013. Modified EBITDAX was $8.3 million for the six months ended June 30, an increase of 2.4% compared to a modified EBITDAX of $8.1 million for the same period of 2013.

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 with several operators in the Williston Basin of North Dakota. In South Texas the Company currently participates in approximately 35,000 gross, 9,100 net acres in Zavala and Dimmit Counties.

During the quarter, the Company expanded its footprint in South Texas through an acquisition of an additional 12,100 gross, 3,300 net acres in Dimmit County, Texas. The acreage is a prospective for the Escondido, Olmos, San Miguel, Austin Chalk, Eagle Ford Shale, Buda Limestone, Del Rio, Georgetown, and the Edwards formations. Our current focus on this newly-acquired acreage is the Buda limestone formation in which we have drilled two test wells to date.

In the Booth Tortuga acreage block, which is operated by Contango Oil & Gas and is located in both Zavala and Dimmit counties, the Company has an approximate 30% working interest and an approximate 22.5% net revenue interest in approximately 13,100 gross, 3,500 net acres. The Beeler Number 5 well began producing in late April. The well was completed naturally without fracture stimulation and had a peak early 24-hour flowback rate of 241 boe per day and a 30-day average production rate of 122 barrels of oil equivalent per day.

The Beeler Number 9 well was also completed naturally, without fracture stimulation, and commenced production in late April. The well had a peak early 24-hour flowback rate of 883 barrels of oil equivalent per day and a 30-day average production rate of 326 barrels of oil equivalent per day.

The Beeler Number 16 well was spud on April 18. The well was drilled to a vertical depth of approximately 7,000 foot with dual laterals of approximately 4,000 foot each. The well was completed naturally, again without fracture stimulation.

It commenced production the second week of June. The well had a peak early 24-hour flowback rate of 1,083 barrels of oil equivalent per day and a 30-day average production of 723 barrels of oil equivalent per day. Beeler Number 17 well spud on May 13. The well was completed naturally again without fracture stimulation and also commenced production the second week of June. The well had a peak early 24-hour flowback rate of 1,326 barrels of oil equivalent per day and a 30-day average production rate of 1,109 barrels of oil equivalent per day.

Beeler Number 19 well was spud on June 10. The well was completed naturally, again without stimulation, and commenced production the second week of July. The well had a peak 24-hour flowback rate of 1,458 barrels of oil equivalent per day and during the first 28 days of production the well had an average production rate of 1,204 barrels of oil equivalent per day.

The Beeler Number 8 well was fracture stimulated with 12 stages during the third week in June. A production increase was not realized as a result of the stimulation and it is theorized that the nearby fracture zones were depleted by an offsetting well. The well is still producing, however, and we continue to monitor the well's performance.

Beeler Number 20 well was spud on July 3. The well was drilled to a total depth of 16,574 foot, which included a 9,474-foot lateral, the longest lateral to date in our program. We continue to monitor the early production data from the well, which so far is comparable to the early flowback results of the Beeler Number 17 well.

Beeler Number 17, Beeler Number 19, and the Beeler Number 20 well costs have been approximately $2.6 million gross per well. Going forward, we are currently scheduled to drill an additional four gross Buda wells with Contango during the balance of the year.

The drilling rig utilized in our program with Contango is currently drilling a well at another site in which we do not participate. We anticipate that the rig will return to drill our next participated well in the Booth Tortuga acreage block in early September. All four wells are proposed to be drilled with lateral lengths of over 9,000 foot.

Under an area of mutual interest selection, the Company also acquired a 7.5% working interest in an additional 800 gross, 60 net acres in the Booth Tortuga prospect. This acreage is operated by a private Texas-based company which is now rigging up for a second well in the acreage block. The acreage block lies between the Beeler Number 16 and the Beeler Number 9 well locations.

The first well drilled, Bruce Weaver Number 2, was spud on June 6. The well was drilled to the total depth of 13,290 foot, which included an approximate 6,665 lateral. The well was completed naturally without fracture stimulation and had an initial production rate of 894 barrels of oil.

During the first 10 days of production, the well averaged approximately 760 gross barrels of oil. During the early flowback, the operator has flared the associated gas from the well, which is not included in the additional production rate. The well is currently being tied in to a sales line to capture the gas sales, which has averaged approximately 1,000 MCF per day or approximately 167 gross additional barrels of oil equivalent during the first 10 days of production.

The second well proposed in this acreage block, the Bruce Weaver Number 1 well, will also target the Buda formation with an Austin Chalk reentry, resulting in an anticipated overall reduction in the drilling cost of this well. The drill rig has been moved on-site and the well will be spud this week as a reentry into an existing Austin Chalk wellbore, which has substantially reduced the AFE for the well.

I will now move on to our Dimmit County acquisition. On May 7, the Company entered into a participation agreement with a private South Texas-based oil and gas company to acquire 33% of the seller's interest in approximately 12,100 gross, 3,384 net acres in Dimmitt County, Texas. The Company paid $3.9 million to enter into the transaction which included acquisition costs as well as our proportionate share of drilling costs for the initial test well in the prospect.

The initial test well was spud on May 5 and was drilled to a measured depth of approximately 11,297 feet including an approximate 5,000-foot lateral. The well was fracture stimulated during the first week of August with 17 stages. We are currently monitoring the flowback of the fracture stimulation and hydrocarbon fluids from the well.

The second well in the program was spud on June 23. The well was drilled to a measured depth of approximately 11,000 foot including an approximate 4,600-foot lateral. This well is scheduled to be fracture stimulated during the third week of August. A third well in the program is also scheduled to spud in mid-September.

In summary, we continue to test and refine our focus on this region of South Texas due to the potential of the Buda formation, as well as the additional multiple stacked hydrocarbon-bearing formation. This summer we have participated in a dual lateral in the Buda. We have expanded the lateral length to over 9,000 feet and we have fracture stimulated an existing wellbore.

In our newly acquired acreage block in Dimmitt County we have drilled two test wells and fracture stimulated the first well late in July. The second well in that program is scheduled to be fracture stimulated later this month and we are looking forward to evaluating the results.

We have also recently purchased the 3D geomagnetic data package covering just under 4,000 line miles of data in Zavala and Dimmitt County, Texas. Delineation of the data is currently underway by the Company and its consultants with the intent to identify the potential for additional acreage acquisition.

During the quarter ended June 30, the Company realized 538 net barrels of oil equivalent per day of production from this region, which represents an approximate 32% increase over our average net daily production from the area during the first quarter of 2014. We will continue to evaluate results from this region with the intent to enhance our oil and gas reserve potential and to increase our net daily production as we continue to develop these assets.

Now I will move on to the Williston Basin of North Dakota. We participate in 74,280 gross, 2,939 net acres in Williams, McKenzie, and Mountrail Counties, North Dakota. At the quarter's end we had 87 gross, 10.1 net producing wells and 8 gross, 0.09 net wells being drilled or awaiting completion.

During the three months ended June 30 we averaged approximately 660 net barrels of oil equivalent per day from this area, which represents the slight decrease over the first quarter of 2014's average daily production of 679 net barrels of oil. This decrease is primarily due to the divestiture of certain Williston Basin assets. As discussed earlier, the divestiture netted the Company $12.2 million for the sale of approximately 286 net acres and 16 gross, 0.62 net producing wells in Williams and McKenzie Counties, North Dakota.

The sold assets averaged approximately 52 net barrels of oil equivalent per day during 2013. We intend to 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, as well as seek out additional acquisition opportunities in the area that have accretive value to our portfolio of assets.

Before moving on to the question-and-answer portion of today's call, I would also like to highlight that our combined activity in North Dakota and South Texas have produced two successive profitable quarters during 2014 and that we've entered the third quarter with additional flush production from our most recently completed Buda wells. We are currently evaluating the fracture stimulation completion in our newly-acquired acreage with an additional fracture stimulation coming later this month with an additional drill in mid-September.

We have been very active in South Texas this year and, thus far, we are seeing positive results while continuing to delineate and develop our position in the region. We will continue to manage our balance sheet and drilling commitments with the goal of increasing production, reserves, revenue, and cash flow from operations, with the ultimate goal of driving continued growth and profitability for the Company's shareholders.

That concludes our prepared remarks for today. Operator, would you please begin the Q&A session?

(Operator Instructions) Noel Parks, Ladenburg Thalmann.

Good morning. I was just wondering with this string of very solid results from the Buda, compared to some of the earlier results that were a little bit more variable, can you -- do you have a sense of is there a pattern that you guys and the operators kind of cracked the code of what's going to make a successful well there and what might be a less successful well?

I think, as you know, these wells are controlled by natural fractures. And I think, now that we have gone to the 9,000-foot lateral, our chances of hitting those natural fractures has increased as well as the excellent performance by Contango knocking the cost down below $3 million.

It still remains a statistical play. We have had some lesser wells, but it appears right now that the wells that are performing exceptionally are going to not only carry themselves and offer an excellent rate of return, but they will carry some of those lesser wells as well.

Great. The question of the frac stimulation, it is sounding like a number of the wells are performing just fine without it. I think you only mentioned one well; it might have been the Beeler 8 where maybe the reserves had been depleted by an adjacent well. So essentially is there -- are we going to expect most of the wells will be unstimulated going forward or will it just vary from location to location?

I think it is going to vary from location to location and depend on results. We are early on in the pullback for this additional test that we did fracture stimulation on. But we think we explained the reason at the 8; it was offsetting that Dan Hughes well that was the 300,000 barrel well, so we kind of explained the depletion.

But it's still going to be some experimentation as we go forward, much like we did early on in the Balkan also. I think the verdict is still out there.

Great, just one last one. Any thoughts on what DD&A might look like going forward, as you have -- you have had a lot of production coming on, either on a unit basis or aggregate?

Well, it's been running about $30, Noel. With the costs here and the performance of these wells it may come down a bit, but we've been using $30 a barrel.

Okay, great. That's all for me.

Evan Richert, Sidoti.

Good morning, guys. Obviously some good results in the last couple wells you've drilled. I noticed in the press release you talked about Contango drilling outside your AMI right now.

What is your sense for their plans? I don't know how much you communicate, but beyond the end of 2014 how much they plan on drilling in your shared acreage.

We haven't talked with them about 2015, but obviously, with these types of results, they like them as well as we do. And I would anticipate that we would keep that rig saturated throughout the remainder of 2015 as well.

Then being that you have a lot of production coming on, but you also have no wells being drilled with Contango at the moment, is your sense that third-quarter production would be sequentially down from the second quarter? Or do you think wells being added mid-quarter of Q2 will be enough to offset the natural decline?

I anticipate we are going to have a slight increase with the third-quarter production, mainly because that Number 20 well didn't come on until late in the quarter. And it appears to have very similar results to that Number 17 well, which is a very strong -- has been and is a very strong well for us.

Okay. Then, as far as the asset sales go, is there any other acreage you are open to kind of spinning off right now or what are your thoughts on that?

No, we anticipate keeping all of the acreage that we have currently. We just had that opportunity to sell that small acreage position. We just felt like the value was there and went ahead and pulled the trigger on that, but we are not looking to sell additional acreage at this time.

Okay, fair enough. Then last question from me and I will hop back in the queue. What are your thoughts on possibly taking an operating role at some point in 2015? Is that something you are considering or you happy with the role you are in now?

No, we are looking at acquiring acreage both in Texas and North Dakota for our own account and operating it at some point.

Okay, that's it. Thanks, guys.

(Operator Instructions) [George Gaspar], private investor.

Yes, thank you. Keith, looking at the net number for the June exit point and what you did for the second quarter in total, this sale of the assets in Williston now, will there be a drawdown in the third quarter from that sale? Or was that executed in such a manner that the deduct was done totally in the second quarter for the sale?

No, it's done. Those averages were after the sale, George, especially for the June production.

Okay, so effectively would there have been production in there from that sale in April and May?

Yes, there would have been.

(multiple speakers) Just looking at -- trying to come up with a number there would have to be a deduct in the third quarter, but before adding the add-ons that are coming your way overall, in particularly the Buda.

That's correct.

All right. But you should have some pretty good uplift in the third quarter for the Buda, because you got one well that's not included with pretty good flow and you got a well previously that was included in your June period. But that was only for a couple weeks so that didn't really get related on a quarterly total basis.

So I assume that there's some -- potentially some pretty decent momentum here. Am I judging that correctly?

I think that you are. We anticipate an uptick. I can't tell you exactly what it's going to be, but, in my opinion, it's going to be better than the second quarter.

Okay. Then in the drilling in the Buda going on now are you continuing to do just open hole? I know you're doing lat growth and you're going out longer periods. Are you actually piping on the lateral to any extent in any of these most recent wells? Can you identify that?

In the Booth Tortuga area we have only done one -- we have only run the pipe in one and that was the Number 8. All of the rest have been open-hole stimulation.

I see, okay. And that's the continuing process, then. Actually you are still continuing -- so you are going out further on your lat rows and there is still consistency in completing them on an open whole basis and getting those flows coming back?

That's correct. Again, as I mentioned earlier, George, the 9,000-foot laterals we have more of a chance to hit these natural fractures and it's bearing out that we apparently are because the wells' performance are bearing testimony to that.

I see, okay. All right. Then in terms of the going forward process, in the wells that you have yet this year with Contango and partnership, where are you looking at those being positioned, more to the west or south of the configuration of where you have been drilling through the Number 20?

Well, actually the number 20 was quite a bit west. The additional wells that I have seen now are in between that Number 6 well, which is an outstanding well, and the Number 20, so we are kind of in-filling, if you will.

I got you, okay. So that's your target for the remainder of the year in terms of that partnership then?

That's correct. There could be some changes that need to be made because of all things the Beeler Ranch has hunting restrictions starting in about a month. They may have to move some locations because of that.

I see. Okay, all right. Then one question on shares outstanding, I noticed in the release that you did the number of shares out for the first -- for the three months ended June on a year-to-year basis is up 555,000. Can you identify where all those shares went in terms of the increase in share count?

Those were option exercises.

So totally option exercises?

Predominantly, yes.

Okay. All right, thank you.

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