US Energy Corp (USEG) 2012 Q2 法說會逐字稿

Good morning. My name is Ben, and I will be your conference operator today. At this time, I would like to welcome everyone to the US Energy Corporation second-quarter 2012 highlights, operational, and financial results conference call. All lines have been placed on mute to prevent any background noise. Thank you. I would now like to turn the conference over to Mr. Reggie Larsen, Director of Investor Relations of US Energy Corp. Sir, you may begin your conference.

Thank you, Ben. Good morning ladies and gentlemen, and thank you for joining us today. Joining me this morning is Keith Larsen, Chief Executive Officer of the Company, who be providing an overview of the quarter and an operations update, and Bryon Mowry, the Principal Accounting Officer for the Company, who will be providing the financial review for today's call. In terms of an agenda, we will provide you with an update on our operating initiatives for the quarter ended June 30, 2012, as well as the period subsequent to quarter end. We will also conduct a financial review of the quarter and finish with the question-and-answer portion of the call.

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 US Energy's management. These and all statements other than statements of historical fact are forward-looking statements within the meaning of Section 21-E of the Securities and Exchange Act of 1934 and Section 27-A 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, 2012, which we filed yesterday. Our Form 10-K for the year-ended December 31, 2011 and our filings with the SEC, all of which are incorporated herein by reference. I would now like to turn the call over to Keith Larsen.

Thanks Reg, and good morning ladies and gentlemen. I will begin the call with an overview of our quarter ended June 30, 2012 operational highlights. At June 30, 2012 the Company had 48 gross, 13.96 net producing wells, which includes 32 gross Williston Basin wells, three gross Gulf Coast wells, 11 gross Austin Chalk Wells in our Booth-Tortuga prospect, and two gross Eagle Ford Wells. The Company produced 118,783 BOE during the three months ended June 30, 2012, with average daily net production during the quarter of 1,305 BOE per day. This represents a 16% increase from production volumes in the second quarter of 2011, and a 6% sequential increase from production volumes in the first quarter of this year. During the first six months of 2012, the Company received an average cash flow of $2.1 million per month from its oil and gas production. Revenue from the sales of oil and gas were $8.5 million, as compared to $7 million in the second quarter of 2011, an increase of 21%.

Moving on to operations, in the Williston Basin of North Dakota under the Statoil Program, we completed 1 gross, 0.04 net well during the quarter. The State 36-1 well, which is the second infill well in the state unit, was completed in mid-June and had an initial production rate of 4,182 gross BOE per day. Two additional gross wells are anticipated to be drilled with Statoil during the balance of 2012. Drilling and completions continued under the Savannah program during the quarter at an aggressive pace. During the quarter, 4 gross, 0.83 net wells were completed in the Yellowstone and SE HR prospects. The Skorpil number-one well had an early 24-hour flow-back rate of 1,533 BOE per day. The CDK number-one well had an early 24-hour flow-back rate of 1,449 gross BOE per day. The Larsen number-one well had an early 24-hour flow-back rate of 1,215 BOE per day.

Slawson Exploration Company operates one unit in the SE HR acreage block. The Hatchet number-one well commenced production on May 7, with an early 24-hour flow-back rate of 1,091 BOE per day. Subsequent to the quarter's end, three additional wells were fracture stimulated under this program, with 35 stages and also turned over to production. The Skogen number-one well had an early 24-hour flow-back rate of 1,839 BOE per day. The Kepner number one had an early 24-hour flow-back rate of 1,871 BOE per day. The Wells number-one well had an early 24-hour flow-back rate of 1,017 BOE per day.

Currently, the operator is drilling in the horizontal section of the wellbore in the Witt number-one well. The well is scheduled to be fracture stimulated in September of this year. Our current working interest and net revenue interest in each of the mentioned wells are available in our press release published yesterday for reference. Our reported initial production rates in the Savanna program to date have been flowed back through a restricted choke. Looking at the program going forward, an initial well has now been drilled in each of the Yellowstone acreage units, and therefore, all leases are now held by production. The operator is now focusing on drilling the remaining SE HR initial well units through early summer of 2013.

Moving on to our Daniels County, Montana acreage, on June 8, 2012, the Company sold an undivided 87.5% of our acreage to a third party for $3.7 million. Under the terms of the agreement, we retained a 12.5% working interest in the acreage and reserved overriding royalty interest in leases equal to the positive difference between existing burdens of record and 21%. The purchaser also committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formation on or before December 31, 2015. We delivered an 80% NRI to the purchaser and a 1% overriding royalty interest to a land broker. We also paid the land broker a 10% commission for the cash consideration paid by the purchaser. This sale represented a premium to our investment in the acreage.

In addition to our success in the Williston Basin, the Company has a 30% working interest in two oil prospects in Zavala and Dimmit Counties in South Texas with Crimson Exploration. The prospects target the oil window of the Eagle Ford Shale Play. The two prospects bring the Company's participation in the region to 13,785 gross, 4,136 net acres. It is estimated that under current spacing, that there is a potential for the Company to participate in 114 gross, 34 net wells in both prospects combined. The KM Ranch number-two well in Zavala County, our second well in the Leona-River acreage block, was drilled to a total measured depth of 12,875 feet, including a 6,100-foot lateral in the first quarter of 2012. The operator recently completed the well with 16 stages of fracture stimulation. As previously disclosed, Crimson delayed the completing of this well in order to further analyze completion techniques being utilized by other area operators, which has resulted in recent success in the area. The Company has an approximate 30% working interest in 22.5% NRI in this well in the overall program, and we look forward to announcing the flow-back results in the coming weeks.

Finally, before turning to the financial portion of the call, I'd like to provide an update on the Mount Emmons project. The Company is scheduled to complete and submit to the United States Forest Service prior to year-end 2012, a mine plan of operations for full mine development of the Mount Emmons molybdenum project. Although the Company currently remains open to a potential federal land exchange, it's significant value could be obtained for our shareholders, the Company does not believe that legislation will be introduced in Congress this year due to the current political climate in Washington. As a result, the Company will be focusing its efforts toward actively pursuing the permitting of the Mount Emmons molybdenum project, while leaving the option to pursue an exchange open. The Company will also fully initiate a partner marketing campaign upon the filing of the mine plan of operation.

I would like to now turn the call over to Bryon Mowry, the Company's Principal Accounting Officer, to review the financial portion of the call.

Thank you, Keith. Our operating revenues increase by $1.5 million to $8.5 million during the quarter ended June 30, 2012, as compared to revenues of $7 million during the quarter ended June 30, 2011. This is a 21% increase from comparing the second quarter of 2012 to the second quarter of 2011. The operating revenue increase was primarily due to higher oil sales volumes. The sales volumes in natural gas and NGLs were lower as were the average sales price for the three sales products.

Operating revenues for the second quarter of 2012 reflected an increase of $187,000 when compared to operating revenue realized during the first quarter of 2011. The increase is primarily due to the higher oil production during the second quarter of 2012. Production volumes for the three months ended June 30, 2012 averaged approximately 1,305 BOE per day, up 16% from the second quarter of 2011, and an increase of 6% in production volumes from the first quarter of 2012. Our average realized price of $71.74 per BOE was $3.15 per BOE higher during the second quarter of 2012 then realized prices from the second quarter of 2011, but down approximately $2.66 per BOE from the realized prices in the first quarter of 2012.

Operating income from oil and gas operations was $1.4 million during the quarter ended June 30, 2012, as compared to the operating income of $1.9 million from oil and gas operations during the quarter ended June 30, 2011. The decrease in earnings from oil and gas operations is primarily due to, A, a $523,000 impairment taken on our proved properties during the quarter, B, a net increase of $603,000 in lease operating expenses, and C, a net increase in our DD&A of $910,000. These increases in costs were partially offset by the increases in revenue due to higher production during 2012 when compared to 2011. Direct operating income from oil and gas operations decreased by approximately $538,000 from the three months ended June 30, 2011 and decreased by approximately $410,000 when compared to the three months ended March 31, 2012. Our DD&A rate was approximately $33.92 per BOE for the second quarter of 2012, compared to $30 and $0.46 per BOE for the first quarter of 2011, and $32,000 -- excuse me $32.50 per BOE for the first quarter of 2012. The major reason for the increase in our DD&A rate when compared year-to-year is our increase in drilling and completion costs in the Williston Basin, the underlying crude reserves volume, and estimates -- estimated cost to drill and complete proved undeveloped reserves.

The drop in the deviate from the fourth quarter of 2011 to the first quarter in 2012 was partially the result of the sale of a portion of our undeveloped acreage in December 2011 and January 2012. Our lease operating expense for BOE including workover costs was $13.72 per BOE for the three months ended June 30, 2012. This rate compares to $12.56 per BOE for the quarter ended June 30, 2011 and a rate of $17.94 for the quarter ended March 31, 2012. The main reason for the increase in the LOE rate when comparing quarter-to-quarter is that during the quarter ended June 30, 2012, we had $321,000 in workover expense. When comparing the second quarter of 2012 to the first quarter of 2012, our LOE rate has decreased by $4.22 per BOE, primarily due to a decrease of $397,000 in workover costs. During the second quarter of 2012, we recorded income of operations of $245,000, compared to a loss from operations of $200,000 during the second quarter of 2011 and a loss during the first quarter of 2012. During the quarter ended June 30, 2012, we recorded a net loss of $990,000 after taxes, or $0.04 per share, as compared to a net loss after taxes of $75,000 or less than $0.01 per share for the quarter ended June 30, 2011. During the first quarter of 2012, we recorded a net loss of $381,000, or $0.01 per share.

Moving to our results for the six months ended June 30, 2012, our operating revenues increased by $3.2 million to $16.9 million, as compared to revenues of $13.7 million during the six months ended June 30, 2011. This is an increase of 23% when comparing the first six months of 2012 to the first six months of 2011. The operating revenue increase is primarily due to higher oil sales volumes. The sales volumes in natural gas and NGLs were lower, as were the average sales price for the three sales products. Production volumes for the six months ended June 30, 2012 averaged approximately 1,268 BOE per day, up 12.8% from the first six months of 2011. Our average realized price of $73.03 per BOE for the six months ended June 30, 2012, was $5.69 higher per BOE than during the six months ended June 30, 2011.

Operating income from oil and gas operations was $3.2 million during the six months ended June 30, 2012, as compared to an operating income of $1.8 million from oil and gas operations during the first six months of 2011. The increase in earnings from oil and gas operations is primarily due to, A, higher oil sales volumes in 2012 when compared to 2011, a net decrease of $2.6 million in lease operating expenses, and a net decrease of $1 million in workover costs. These reduction in cost were partially offset by an increase in our DD&A of $1.8 million, and a $523,000 impairment taken against our crude oil and gas properties during 2012. Our DD&A rate was approximately $33 and $0.23 per BOE for the six months ended June 30, compared to $29.02 per BOE for this first six months of 2011. One of the reasons for the increase in our DD&A rate when compared year-to-year is our increase in drilling and completion costs in the Williston Basin. The DD&A rate can also fluctuate as a result of impairments, divestitures, and changes in our mix of production, the underlying crude reserve volumes, and the estimated cost to drill the complete proved undeveloped reserves.

Our lease operating expense for BOE, including workover costs, was $15.76 per BOE for the six months ended June 30, 2012. This rate compares to $23.02 per BOE for the six months ended June 30, 2011. One reason for the decrease in the LOE rate when comparing year-to-year is that during the six months ended June 30, 2011, we had an excess of $2.8 million in workover expense. During the six months ended June 30, 2012, we recorded a loss from operations of $200,000 compared to a loss from operations of $2.5 million during the first six months of 2011. During the six months ended June 30, 2012, we recorded a net loss of $1.4 million after taxes, or $0.05 per share, as compared to a loss of after taxes of $2.3 million, or $0.08 per share for the six months in 2011.

Our balance sheet remains strong at June 30, 2012, with a working capital of $13.1 million, including cash and cash equivalents of $3.9 million. At June 30, 2012, we had a total debt balance of $9.8 million related to our Remington Village project, and we currently have drawn down $5 million on our line of credit with Wells Fargo. In March 2012, our borrowing base under the senior credit facility increased from $28 million to $30 million as a result of the recent termination based on our December 31, 2011 financial statements, production reports, and reserve reports. We currently have $25 million available under the credit facility.

I'd now like to turn the call back over two Keith for the question-and-answer session.

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

(Operator Instructions)

Your first question comes from the line of Noel Parks from Ladenburg Thalmann. Your line is open. Please go ahead.

Just a couple of things. I was looking at what you were talking about in the Eagle Ford as far as different completions and so forth. And in general, does it seem like the frac intensity, and I guess with that the cost by the operators is continuing to go up? Or is that flattening out and getting a little bit -- are people starting to get more conservative again with the fracs?

Quite honestly, no, we haven't done enough to know about the creep down there, but I've heard the same things that you have, is they are getting some cost creep like they are in the Bakken. But with only having this one lousy share, it's a little difficult to compare to the other costs.

Sure, okay. And we've been aware of course of a lot of different acreage packages on the market out there. Do have a sense of for what you guys would be comfortable with? Have you heard about or seen anything in the Eagle Ford that is in the ballpark of stuff you'd consider picking up over the acreage on?

No, we haven't seen a lot. We've seen some of the costs. I think everybody's heard about Chesapeake valuing their acreage at $30,000 to $50,000. But we're not seeing a lot there. We have see more packages in the Bakken that we are taking a look at.

Okay. And I actually had to drop off for a minute, so I apologize if you guys addressed this, but just in general, since production has been a little bit lumpy, on a unit basis, should we be -- do you guys have any guidance on the cost side?

Well, again, you saw some of our DD&A go up for the Bakken because of the cost creep. I think everybody is aware that. I've heard recently that their costs are starting to come down. There is more competition up there. Some of the operators are demanding lower costs from their service providers, so hopefully we are going to see some reduced costs up there. I think that we, in fact, need it for some of our lower EUR units to be developed, certainly a $10 million plus well, it gets pretty sketchy for economics. So I think the costs are going to come down on the Bakken. And again, I can't comment because we haven't had a lot of experience yet in the Eagle Ford, but I think costs will come down in the Bakken.

Okay, and as far as just G&A trends, any changes you perceive for the rest of the year?

We are trying our best on the G&A. Would like to continue our trend of reducing that, but it's probably going to stay flat.

Okay, great. That is all I had. Thanks.

Thank you. Our next question comes from the line of Jeffrey Connolly from Sidoti & Company. Your line is open, please go ahead.

Have you received any additional AFEs from Crimson?

Except for the completion, except for the completion, no, we have not.

So we are going to have to wait until the KM Ranch [shur] is done before we know how many more they plan on drilling? Or are they -- do guys currently plan to spud one more this year?

We don't have currently have plans, but I've been talking to Alan and if we're successful, and I think he made the comment that we could accelerate the program depending on the success.

Okay, and then can you just give us an update on the Woodbine Sub-Clarksville project?

What we've announced, Jeff, is we are not going to announce any results until we complete our seventh well, and we are currently drilling the sixth well. So within the next couple three weeks, then we will announce the full program.

All right. Thanks, guys.

Thank you. Our next question comes from the line of Mike Wallcup from Long Co Investment. Your line is open, please go ahead.

Keith, you are the only oil and gas Company selling [below book value] at 50%. Management has never bought stock in the open market. You operate nothing, so you have no need for a constant transportation, but need a jet. You have lost money in 17 of the last 18 quarters, totaling $21.5 million, so all of that represents [the pudding]. Two questions, why should we think you or the Board care about the stock price, and why should the Board not replace management if the stock price cannot get back to book value within a year, or just sell the Company?

I addressed that with you individually on many occasions. Operator, could you go to the next question please.

Absolutely. (Operator Instructions) Our next question comes from the line of Barry Lake of Lake Investments. Your line is open. Please go ahead.

Keith, I know at this time you are not allowed to comment on Mount Emmons, but is that -- is there still some progress? Is the line of communication still open with the land exchange?

Yes it is. We certainly not closing any doors. We thought that we would see a lot more support for the land exchange and are hopeful that we will see more support. And if they can get their situation together and have something that's reasonable for shareholders, we will still consider it, but in the meantime, and we've told the other parties that we are going to move forward with permitting the mine.

Okay, but at this point the door is not closed on it? It's just that at this time, they haven't presented anything to you is that correct?

That is correct.

Okay, that is all.

Thank you there are no further questions at this time. Do you have any closing remarks?

Yes, I'd like to end the call by stating that our drilling programs remain active through the midpoint of the year. We will have the full results of the Woodbine Sub-Clarksville seven project in a few short weeks, and we will report the initial results upon a comprehensive evaluation of the program. We also look forward to reporting the results of the KM Ranch number-two with Crimson, upon evaluation of the important test well in the participative programs. The success of this well could be the turning point for a drilling program next year and a potential growth driver for our Company. We also continue to work with our partners and industry peers to seek out additional opportunities in the oil and gas sector, while our active drilling programs continue to be developed. And we will continue to work towards preserving and creating the value that we see in the Mount Emmons project, and will look forward to providing periodic updates on our progress as milestones are met. I would like to thank our audience for joining us today and look forward to updating you in the future. Thank you.

This concludes today's conference call. You may now disconnect.