US Energy Corp (USEG) 2012 Q3 法說會逐字稿

Good morning. My name is Huey and I will be your conference operator today. At this time, I would like to welcome everyone to the US Energy Corporation's third-quarter 2012 highlights, operations, and financial results conference call. All lines have been placed on mute to prevent any background noise.

I would now like to turn the conference over to Mr. Reg Larsen, Director of Investor Relations of U.S. Energy Corporation. Sir, you may begin your conference.

Thank you. Good morning, ladies and gentlemen, and thank you for being with us today. Joining me this morning is Keith Larsen, Chief Executive Officer of the Company, who will be providing an overview of the quarter and an operations update, and Steve Richmond, the Company's recently appointed Chief Financial Officer, who will be providing a financial review for today's call, as well as Mark Larsen, President of the Company, who will be joining us for the Q&A.

In terms of an agenda, we will provide you with an update on our operating initiatives for the quarter ended September 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 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 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 September 30, 2012, which we filed on Friday, November 9, 2012, our Form 10-K for the year ended December 31, 2011, and other filings with the SEC, all of which are incorporated herein by reference.

I would now like to turn the call over to Keith Larsen.

Good morning, ladies and gentlemen. I will begin the call with an overview of the quarter and nine months ended September 30, 2012 operational highlights.

At September 30, 2012, the Company had participation in 79 gross or 14.88 net producing wells, which include 62 gross Williston Basin wells, three Gulf Coast wells, 11 gross Austin Chalk wells, and three gross Eagle Ford wells. The Company produced 106,060 barrels of BOE during the three months ended September 30, 2012, with average daily net production during the quarter of 1153 BOE per day.

During the nine months ended September 30, 2012, production totaled 336,880 barrels of oil equivalent, which is an average of 1229 BOE per day.

The Company recognized $24.5 million in revenues during the nine months ended as compared to $22.1 million during the same period of the prior year. The $2.4 million increase in revenue was primarily due to higher oil sales volumes in 2012 when compared to 2011.

We continue to focus on increasing production, reserves, revenue, and cash flow from operations while managing our level of debt and seeking out additional growth opportunities in the second segment of our business. In that regard, we announced on September 21, 2012 that the Company entered into a purchase and sale agreement with an undisclosed seller to acquire interest in producing Bakken and Three Forks formation wells and related acreage in McKenzie, Williams, and Montreal Counties North Dakota.

Under the terms of the agreement, the Company acquired working interest in 23 drilling units with an estimated 294,000 BOE in proved reserves for 2.3 million after adjusting for related revenue and operating expenses from the effective date through September 21, 2012.

USE's working interest in the drilling units averages 1.45% and ranges from less than 1% to approximately 5%. There are currently 27 gross producing wells in the acreage. Of these wells, 25 are producing from the Bakken formation and two are producing from the Three Forks formation. All of the approximate 400 net acres are currently held by production and produce approximately 47 BOE per day net to USE.

On a going forward basis, there is the potential for USE to participate in an additional 135 gross wells from the Bakken and Three Forks formations combined and the Company will be heads-up for its proportion of the interest on all new wells drilled within the units. Since the closing of the purchase, one of the operators, Oasis, has drilled the Ash Federal 5300 11-18T well, which recently had an IP of 2430 BOE. Oasis has also permitted four additional gross wells near this location, two targeting the Bakken formation and the remaining two targeting the Three Forks formation.

In addition to the Oasis wells, Emerald Oil & Gas has also permitted three gross Bakken wells. We anticipate these wells to be drilled beginning in the first quarter of 2013.

Under the Statoil program in the Williston Basin in North Dakota, the state 36-1 #4H well, which is a Three Forks formation targeted well is scheduled to spud in December. The well is the fourth well in the State unit and the second Three Forks formation well in that unit.

In addition to the State Three Forks infill well, Statoil has also permitted three gross additional infill wells in the Hovde unit, with one of the wells targeting the Bakken formation and the remaining two targeting the Three Forks formation. We anticipate these wells to be drilled in the coming months.

During the quarter, two gross, 0.11 net wells were drilled in the SE HR acreage block under the Zavanna program. The wet #1H well was completed in early November and had an early 24-hour flow back rate of 1564 BOE per day. The Barker #1H well was drilled to its total depth in October and is scheduled to be completed in mid-November. Subsequent to the quarter end, the Bunning #1H well is in the final stage of drilling the horizontal portion of the wellbore and also is scheduled to be completed in late November.

The Company has also elected to participate for our proportionate share 8.75% approximate in saltwater disposal facilities in each acreage block under the drilling program with Zavanna. The project is currently underway and is expected to be completed in the fourth quarter of 2012.

These facilities consist of gathering lines and a salt water disposal well in each acreage block which are expected to reduce the water disposal costs and to ultimately reduce our cost per barrel of oil produced from the program. As I have previously stated, all of the units in the Yellowstone acreage block are held by production.

Going forward, we believe the operator will continue to focus on drilling the remaining SE HR initial well units through early summer of 2013 as well as begin to drill infill wells in 2013. The Company will gain a better insight into the 2013 Zavanna drilling program at a scheduled partners meeting later this week.

On June 8, 2012, the Company sold an undivided 87.5% of our acreage in Daniels County, Montana to a third party for $3.7 million cash. Under the terms of the agreement, we retained a 12.5% working interest and approximately 20,000 net acres reserved overriding royalty interest in leases equal to the positive difference between existing burdens of record and 19%. The purchaser committed to drill a vertical test well to depths sufficient to core the Bakken and Three Forks formation on or before December 15, 2015 and to carry us for our 12.5% working interest on that well.

Apache Corporation recently announced that they had acquired in excess of 300,000 net acres in Daniels County. During the third quarter, Apache spudded two Bakken and two Three Forks Wells approximately 15 miles northwest of the Company's acreage. We will be closely monitoring the Apache results as they become available.

In addition to our active programs in the Williston Basin, the Company also has a 30% working interest in two oil prospects in Zavalla and Dimmit Counties in South Texas with Crimson exploration. The two prospects bring the Company's participation in the region to 13,785 gross or 4136 net acres. The KM Ranch #2 well in Zavala County, Texas, our second well in the Leona River acreage block, was drilled to a total measured depth of 12,875 feet, including a 5250 foot perforated lateral in the first quarter of 2012.

We completed the well in August with 16 stages of fracture stimulation. The well had a peak 24 hour gross flow back rate of 511 BOE which consisted of 457 barrels of oil and 326 Mcf of natural gas. We plan to further analyze completion techniques being utilized by other area operators and believe that a longer lateral with additional fracture stimulation stages may be the key to unlocking this area's potential for development.

In addition to the Eagle Ford formation drilling program, a private operator has tested the Buda formation immediately east of our Booth-Tortuga prospect with reportedly promising initial results. We have discussed the Buda formation test well with Crimson in the near future and we plan to announce our South Texas drilling program when our 2013 budget is finalized before year-end.

In May 2012, we acquired a 26.5% initial working interest in approximately 6700 gross acres in the Woodbine Sub-Clarksville 7 project area in northeastern Texas with Mueller Exploration. The seven prospects were drilled in succession from June through August of 2012. Two of the gross wells, 0.4 net are currently being evaluated for production potential and the remaining five, 1.33 net, were deemed to be nonproductive.

Before turning to the financial portion of the call, I would like to provide an update on the Mount Emmons project. On October 10, 2012, the Company filed a preliminary Mine Plan of Operations with the US Forest Service in Delta, Colorado. The preliminary plan is under review by the US Forest Service.

On Friday, November 9, U.S. Forest Service notified the Company that additional time is needed to complete the review but will not exceed 60 days. Upon acceptance by the U.S. Forest Service, the Mine Plan of Operations will be released to the public in its entirety.

Regarding the Federal land exchange effort, there has been no progress on this front since the effort was suspended in June of 2012, primarily due to the uncertainty of the outcome of the Federal elections and the unknown makeup of Congress. The Company's primary focus at this time is to finalize and pursue the Mine Plan of Operations, particularly the initiation of the National Environmental Permitting Act, NEPA, process which is expected to follow the Mine Plan of Operations acceptance by the U.S. Forest Service. Once the Mine Plan of Operations has been formally accepted by the U.S. Forest Service, the Company plans to issue a press release outlining the components of the Mine Plan of Operations.

In addition to the filing of the Mine Plan of Operations, the Company has also installed a plumbing system which allows for the capture and control of the water flowing from behind the bulkhead in the mountain. The intent of this system is to reduce the influent metals loading by not allowing oxidation while the water travels from within the mine to the surface. By capturing the water via the plumbing system, the Company has reduced the influent metals loading by 33% to as much as 50% which has resulted in decreased chemical costs to treat the water as well.

The Company has also installed and tested a new filtration system which may allow for 24-hour operations in the future. Initial testing has indicated that the system could reduce our overall water recycle volumes by approximately 40% when converted to 24-hour operations. The overall goal of the combined projects is to reduce the annual water treatment plant operational costs by approximately $300,000 to $500,000 annually beginning next year.

The Company has embarked on additional cost-cutting measures Companywide including the sale of its corporate aircraft and related facilities and a reduction in our staff. We believe these measures will also result in a reduction of G&A expense approaching $1 million in 2013.

I would like to now turn the call over to Steve Richmond, the Company's CFO, to review the financial portion of the call.

Thank you, Keith. During the three months ended September 30, 2012, we recorded a net loss of $1.9 million after taxes or $0.07 per share as compared to net income after taxes of $268,000 or $0.01 per share for the quarter ended September 30, 2011.

During the nine months ended September 30, 2012, we recorded a net loss of $3.3 million after taxes or $0.12 per share as compared to a net loss after taxes of $2 million or $0.07 per share for the nine months ended September 30, 2011. Both the quarter ending September 30, 2012 and year-to-date earnings have been negatively impacted by one-time charges. During these nine months, we have recorded approximately $4.2 million in non-cash impairments including a $2 million impairment on Remington Village, a $1.8 million impairment on our corporate aircraft, and a $523,000 ceiling test write-down on our oil and gas assets.

In the financial and operational release that went out last Friday, we presented an EBITDAX table showing earnings before interest, income taxes, 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. We used this non-GAAP measure internally to manage our business and believe it is a valuable tool in measuring operating performance. EBITDAX was $9.8 million for the nine months ending September 30, 2012, an increase of 66% from $5.9 million for the same period of 2011.

A reconciliation of EBITDAX to net income is presented in the earnings press release which was published on Friday, November 9 and is available on the Company's website for review.

A similar improvement is reflected in our cash flow from operations which increased from $2.4 million during the nine months ended September 30, 2011 to $9.3 million during the same period of 2012. As Keith noted, during the nine months ended September 30, 2012, our operating revenues increased to $24.5 million as compared to revenues of $22.1 million during the nine months ended September 30, 2011. This 11% increase is primarily due to higher oil sales volumes in 2012.

Our average realized price for the nine months ended September 30, 2012 improved to $72.71 per BOE from $68.31 per BOE during the nine months ended September 30, 2011. Lease operating expense per BOE including workover costs was $15.83 for the nine months ended September 30, 2012 compared to $20.07 per BOE for the nine months ended September 30, 2011 and is down primarily due to lower workover costs in 2012.

Our DD&A rate was approximately $32.89 per BOE for the nine months ended September 30, 2012 compared to $30.17 per BOE for the first nine months of 2011.

Moving to the three months ended September 30, 2012, our operating revenues decreased by $769,000 to $7.6 million as compared to revenues of $8.4 million during the three months ended September 30, 2011, primarily due to lower natural gas sales from our Gulf Coast wells. Our average realized price for the three months ended September 30, 2012 improved to $72.03 per BOE from $69.95 per BOE during the same period in 2011.

Lease operating expense per BOE including workover costs was $15.95 for the three months ended September 30, 2012. This rate compares to $15.07 per BOE for the three months ended September 30, 2011.

Our DD&A rate was approximately $32.15 per BOE for the three months ended September 30, 2012 compared to $32.13 per BOE for the same period of 2011.

We continue to focus on cutting our costs and as a result, general and administrative costs were down $170,000 and $1.1 million during the three and nine months ended September 30, 2012 respectively from the same periods in 2011. Through our hedging program, we have had 600 barrels of oil per day through 2013 using costless collars. Our weighted-average floor price for October 2012 through December 2013 is $90.66 per barrel and our weighted-average ceiling price is $104.76.

Finally at September 30, 2012, we remain in good position to fund our forward drilling programs with $3.7 million in cash and cash equivalents, working capital of $13.9 million, and $22 million in borrowing capacity remaining under our $30 million line of credit with Wells Fargo.

I would now like to turn the call back over to Keith Larsen for the Q&A session.

Thanks, Steve. That concludes the prepared remarks that we have today. Operator, would you please open up the Q&A session?

(Operator Instructions). Curtis Trimble, Global Hunter Securities.

Good morning, everyone. Looking at the Daniels County in Montana kind of first off, has the partner permitted that initial well that they committed to drill yet?

They have not.

I guess looking at participation, uses of capital for the fourth quarter, can you kind of benchmark maybe a range of capital expenditures expected and maybe number of wells that you would expect to participate in for the fourth quarter?

Probably in the neighborhood of $5 million to $7 million is what we will spend in the last two months.

And number of wells maybe on a gross or net basis or maybe just put a range on that one?

They are predominantly probably going to be the Williston Basin wells, so probably 0.4, 0.5.

Thank you very much.

Jeffrey Connolly, Brean Capital.

Good morning. Have you guys reached the pool payout on the second group of Brigham wells in this recent quarter?

We have not. We have not reached payout on the first group either.

Okay and then do you still expect the first group will be in the first quarter of 2013 or can you update us on when you expect the pool payout to kind of hit?

Midyear, midyear 2013 and probably because of the large workover that we had in the first group, both groups will pay out at about the same time.

Okay, all right, thank you.

George Gaspar.

(technical difficulty) to talk about the forward expenditures in a little more detail. Could you outline what you are projecting in terms of drilling expenditures for the fourth quarter and at this point, what your drilling program expenditure target is for 2013? And could you talk a little bit about how you expect to finance it?

Sure, George, first of all, I think we are going to spend somewhere in the neighborhood of $5 million to $7 million for the final part of November and December and that will predominantly and in fact all of it will be in the Williston Basin and that depends on weather and the performance of the operators, so probably 0.4, 0.5 net wells.

As far as our budget for next year, we're working on that currently with our partners and we will present that to our Board of Directors at our meeting in December for their approval. After that we will give guidance and put out what our budget is and what has been approved.

Okay, can you talk a little bit about what your assumptions are on where you're going to concentrate your effort next year relative to performance from the overview from this year?

Obviously we are going to continue our program up in the Williston Basin and in fact we are seeing additional non-op packages that are coming to us. It depends on how we do on these two possible completions down on this Texas program that we did with Mueller. We haven't produced the wells yet, but they are looking promising and if we do get some success there, there will be some additional development down there and it's just too early to tell down there.

But obviously through our cash flow and through our debt, we feel that we are well-funded going into next year and we will stick to that.

Okay, my second question was going to be on the two wells that you made reference to in Texas. Can you explain a little bit about -- if I remember originally there was apparently just one well that looked like it had some potential and then you got two wells you are suggesting currently. So could you tell us a little bit about the depth, what you are trying to do actually in trying to bring these wells to some type of production?

Yes, well, we still have the one Woodbine well that we believe we've got some updip if you will that we plan on drilling that sometime in the future, maybe the first quarter. The other two were formations that were a bit of a surprise when we were going after that down dip and we still have to do some testing. They are both shallower. One is gassy and one is oily.

Okay, and do you have any target on what you could maybe when you can get a handle on what the potential might be there?

You know, it's just too early, George, to tell. I could guess but I'd prefer that we wait for the results and then if we do some infill drilling, then we will define both formations better.

In terms of speaking about infill drilling, how much of the -- in terms of the shallower formation that you are attempting to get a completion on, how extensive is that shallower formation and the acreage that you have at this point in time?

It's just too early to tell, George. It's not a seismic play and there are thin seams. They are only 10 to 12 foot thick so we just have to keep drilling it out until we find what the boundaries are on it. So it's just too early to say.

Okay, thank you.

(Operator Instructions). We have a follow-up from George.

Thank you. Keith, about the Eagle Ford, you mentioned about this well structure that apparently the Buda that's apparently evident, potentially evident in acreage that you have under your control with your partners. Exactly how far -- can you give us an idea how far away the indicated success in that formation is from where you might be able to drill?

Sure. What they did is they've drilled five wills now, which is an indication to me that they have had some success and they are within a half a mile east of our boundary in the Booth-Tortuga area.

Okay, what's the depth on that formation relative to what you've drilled up to in the first wells?

It's right below the Eagle Ford. So we're talking about 6500 feet, something like that.

Okay, and then a question on the real estate project, can you bring us up to date on what's going on there as far as your utilization, your occupancy, and what your thoughts are going forward on that? Is there any interest showing up and do you actually have it on the market yet? Could you talk a little bit about what your thoughts are on that?

George, this is Mark. We have relisted the property. We are focusing primarily right now on reduction of expenses associated with the property. I think we will have -- we will have some success there. The marketing effort again is early stage but we are going to put it out there. We see it as a non-core asset and we would like to sell it, so we are moving in that direction both on the sale side as well as cost reduction, expense reduction.

Okay, all right, one question generally about with the pressure on the stock here, and to its current price level, is there any entertaining of the possibility of buying stock back? I know that that's different than drilling -- drilling wells but at this price level relative to your book is not -- is that not an unreasonable approach or is it just that the financial situation wouldn't allow it to happen?

George, anything that we did right now, we would have to take that out of our debt facility and I don't think that we will be taking debt down to buy back our stock. We need that money to generate additional revenues in the drilling of the wells.

Okay, all right, and as -- can you just relate a little bit about -- you talked about average pricing on a per barrel basis nine months quarter in this -- was it $72 range? How are prices -- I know the market's pull back in WTI. How would you be looking at your average price today in the fourth quarter relative to third quarter? What kind of a dip would you have in there?

Of all things, George, and you and I have talked about this before, we got hit in that third quarter with the differential from the Bakken prices to WTI. They got a size $20 plus for some time in there and recently we've seen that narrow down into even less than $5 a barrel. And so if those prices hold and I think probably everybody is aware it is the unit trains that they have put in and they have built a lot of capacity up there, they are also putting in additional pipelines and they're going to need it. They are up to 700,000 barrels a day Bakken-wide.

So those are the factors that are going to affect us as well as the price moving up and down but I think we got down sometime in July, August where we were only getting $65, $70 a barrel. That was even with us at $85 or $90 and additionally that's why we and I believe others have hedged 600 barrels a day at an average price of about $90 on the store and about $105 on the ceiling, so we think we are protecting our cash flow in that regard.

I see. Okay. And as far as the view on forward pricing differential, do you think that it is going to be narrower because of the ability to evacuate more oil out of the area by tanker? It seems like it's going that way. Does that influence the differential?

Sure it does. I will take away capacity influences and probably, George, what we are going to see is some areas of that spread is good to get bigger and then they will overbuild and it will narrow down because of the stories I have heard, they are going to take it up to over one million barrels a day and until that transportation constrainment is taken care of once and for all, you're probably going to see some volatility there.

Okay, then your production per day was of course in 1100 plus range. Was that impacted at all in the third quarter by workover and what are you experiencing this quarter in terms of workover that would tend to slow production? Give us some thoughts on that.

Now that we are involved with the number of wells that we are, we are seeing additional workovers as well as just the age of the wells. And in my opinion just looking back at it, I haven't looked at it statistically but we did do a lot of workovers in the third quarter. Currently we don't have a lot of workovers going on but we are bringing on -- just putting on pump some wells with Zavanna and of course your downtime there to install the pumps and so forth and you are not going to have any oil until they get put on.

So overall I think we're starting to get stable production. We are involved in enough wells where we can start building from here. These wells are going to be 20-year plus wells up in the Bakken and they are going to have some workovers but the LOEs on these -- on the barrel per oil we think it's real very reasonable.

As I mentioned, were just about to pay out probably mid-year next year on that first set of 10 wells with Brigham. It took a bit longer than what we had anticipated but once we get to that point, that's just generating additional cash flow, so we are pleased with what we've got.

Okay, all right, thank you.

Thank you, sir. Presenters, there appear to be no further questions at this time. Do you have any closing remarks?

Yes, I would like to end the call by stating that our drilling programs have remained very active through 2012 and expect steady drilling in 2013. We are working with our partners to develop our 2013 budget and proposed drilling schedule in order to provide the market with a look at our growth potential as we move into the next full year of drilling and completing wells.

We also have a tremendous opportunity to create value for our shareholders with the Mount Emmons project. I look forward to updating you on the progress as certain milestones are met. We have made significant strides in reducing the Company's overhead and it is our ultimate goal to continue to grow our portfolio of producing assets and to create long-term value for the Company's shareholders.

I'd like to thank everybody in the audience for joining us today and we look forward to the next call.

Thank you, sir. This concludes today's conference call. You may now disconnect.