US Energy Corp (USEG) 2011 Q4 法說會逐字稿

Good morning. My name is Karen and I'll be your conference operator for today.

At this time, I would like to welcome everyone to the US Energy Corp. 2011 year-end selected highlights financial results and operations update. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions)

I would now like to turn the conference over to Mr. Mark Larsen, President and Chief Operation Officer of US Energy Corp. Sir, you may begin your conference.

Thank you, Karen. Good morning, ladies and gentlemen. Thank you for joining us today.

Joining me this morning is Keith Larsen, Chief Executive Officer of the Company, who will be conducting the main portion of today's call, and Bryon Mowry, our Principal Accounting Officer, who will be reviewing the financial section of today's call. In terms of an agenda for today's call, we will provide you with an update of our operating initiatives for the year ended December 31, 2011, as well as the period subsequent to year-end, and conduct a financial review before taking your questions in the Q&A portion of the call.

Before getting started, 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-K for the year ended December 31, 2011, which we filed Wednesday, March 14, 2012, and our other filings with the SEC.

I'll now turn the call over to Keith.

Thanks, Mark. Good morning, ladies and gentlemen. Thank you for joining us.

2011 was another year of growth in the E&P sector for US Energy Corp. We continued to increase revenue from our oil and gas portfolio, witnessed significant initial production rates, as well as stabilized production from both of our participated Bakken drilling programs, and expanded our strategic partnerships to include the Eagle Ford oil play. Also at year end, we monetized undeveloped acreage in the Williston Basin, in order to demonstrate value to our shareholders as well as maintain a strong balance sheet going into 2012.

The results of this progress are demonstrated by another year of reserve growth, including a 474% increase in the proved undeveloped category. Based on these year-over-year reserve increases, our credit lender, BNP Paribas, has recently informed us that they intend to increase the commitment amount of our credit facility to $100 million from $75 million, and increase our borrowing base to $30 million. This progress has allowed us to budget for a $48.1 million drilling program in 2012, which is anticipated to be funded from cash flow from operations, as well as our credit facility with BNP Paribas.

Turning to an overview of our 2011 operational highlights for the year ended December 31, 2011, we drilled 20 gross, 4.1 net, wells during the year in all of our programs, and we once again realized a 100% success rate in our drilling initiatives in the Williston Basin. As a result of our growth, we recognized record revenues from oil and natural gas production of $31 million. During the year, we produced 442,000 BOE, or 1,212 BOE per day, which is a slight decrease from our 2010 average daily production, primarily due to the impacts to our programs as a result of unprecedented weather-related issues in North Dakota in the first and second quarters of the year, as well as a backlog of completions in the Williston Basin.

Due to stronger oil prices in 2011, our average net realized price for the year was $69.98, which is over $10 per barrel higher than our average net realized price compared with the same period in 2010. I would also like to point out that over half of our Williston Basin wells have been producing for more than a year now, so we are seeing benefit of stabilized long term production, mixed with five additional high interest wells anticipated to come on line from our two programs in the Basin in the first half of 2012.

At December 31, 2011, our proved reserves totaled 3.1 million BOE, replacing 280% of 2011 production. The total is comprised of 2.7 million barrels of oil, which is 86% of our total reserves, 2.7 BCF of natural gas, and 1,688 barrels of natural gas liquids. At year-end, 56% of our estimated proved reserves were producing. 13% were proved, developed and non-producing, and 31% were proved undeveloped, with oil accounting for approximately 86% of this total. Based on proved reserves, our total estimated PB10 value at year-end was $72.5 million. These numbers represent a 63% increase in reserves and a 39% increase in PV10 value over December 31, 2010.

On January 25, 2012, we sold an undivided 75% of our undeveloped acreage in the SE HR and Yellowstone Prospects. If applied retrospectively to our December 31, 2011 reserves, this sale reduced our proved developed reserves by 41,000 BOE due to acceleration of the reversionary interest of pay-out related to the producing wells. It also reduced our proved undeveloped reserves by 509,000 BOE, reduced our estimated future development cost by $21.4 million and increased our PV10 by approximately $468,000.

Now moving on, and looking ahead to the balance of 2012. At year-end 2011, our Board of Directors approved the capital expenditures budget of approximately $48.1 million for our 2012 oil and gas drilling programs. The CapEx budget is comprised of an estimated $18.4 million to be spent in the Williston Basin of North Dakota in the Rough Rider and Yellowstone/SEHR programs with Brigham and Zavanna, respectively.

$24.9 million in capital expenditures is budgeted to be spent on exploration initiatives in the Eagle Ford drilling program with Crimson, and the remaining $4.8 million originally budgeted for the San Joaquin Basin prospect will be redirected towards other programs over the course of the year. Amounts budgeted for each regional drilling program is contingent upon timing, well cost and success, and could be subject to further adjustment based on timing, weather and other factors.

Moving on to our two drilling programs in the Williston Basin, I'll start with Brigham Exploration, whom most of our audience knows was acquired by Stat Oil of Norway in December of 2011. Since the transaction has taken place, we have seen very little change in terms of who we work with on their operational team, and we expect to continue to have a great working relationship with their group going forward. I'd like to congratulate the entire staff at Brigham for the success of their merger with Stat Oil, and Bud and Dave Brigham in particular for a job well done.

With Brigham Stat Oil, we participate in 15 1,280-acre drilling units in the Rough Rider prospect near Williston, North Dakota. Since inception of our program with Brigham, which began in August of 2009, we have drilled and completed 19 gross Bakken wells and one gross Three Forks well. On Wednesday, we announced the early 24-hour flow back, or initial production rate, from the Lloyd 34-3 #2H well, which was 4,300 BOE per day, and accounts to our highest initial production rate reported in a Company participated well under the program with Brigham.

During the calendar year 2011, the Company drilled three gross wells, 0.6 net, completed an inventory of five gross wells, 1.62 net, and have completed an additional two gross wells, 0.28 net subsequent to year-end. Brigham has notified the Company of three infill wells scheduled to be drilled in the Rough Rider acreage going forward. They are currently scheduled to drill a Bakken infill well in the State 36-1 unit this month, a Bakken infill weld in the Sedlacek Trust 33-4 unit in April, and an additional Three Forks infill well in the State 36-1 unit in August of this year.

On December 15, 2011, the Company also sold an undivided 75% of its undeveloped acreage in the Rough Rider prospect to Brigham for $13.7 million. Under the terms of the agreement, the Company retained the remaining 25% of its interest in the undeveloped acreage and its original working interest in its 20 developed wells in the Rough Rider Prospect.

After the sale, our working interest in the undeveloped acreage in the Rough Rider Prospect ranges from 3.4% to 9.9%. Although our interest in the undeveloped acreage with Brigham and Zavanna has decreased, we feel that this was a prudent move in order to maintain a strong balance sheet in light of the cost creep occurring in the Basin, as well as completion timing uncertainties that risked moving the Company toward its borrowing limits late last year.

In our second drilling program in the Williston Basin with Zavanna, we participate in two parcels, the Yellowstone Prospect and the SEHR prospect. We expect this program will ultimately result in 27 gross 1,280-acre spacing units, with various working interest of up to 35% for our first 10 wells. Our drilling program with Zavanna commenced early in 2011 and we drilled eight gross wells, 2.18 net, during the year. Three gross wells, 0.9 net, were completed in 2011 and the remaining five gross wells, 1.27 net, are expected to be completed in the first and second quarters of 2012.

Currently, we are nearing the completion of drilling out the plugs on the Lang well which was fracture stimulated with 35 stages. We have an 18% working interest and 14% NRI in this well. Also, the Crescent Farms well has been recently fracture stimulated with 35 stages, and we expect to drill the plugs out of that well in late March or early April. We have a 27% working interest and a 21% NRI in the Crescent Farms well.

Additionally, we have an inventory of five wells drilled to a target depth of 20,000 feet currently scheduled to be fracture stimulated between now and June, 2012 under the program with Zavanna. The completion schedule and our interest are as follows. The Skorpil 11-2 31H well is scheduled to begin completion initiative in April, and we have a 23% working interest and an 18% NRI in the well. The CDK 15-22 #1H well is scheduled to begin completion initiatives late in April. We have a 32% working interest and a 25% net revenue interest in the well. The Larsen 29-32 #1H well is scheduled to begin completion initiatives in May. We have a 28% working interest and a 21% NRI in this well. As these wells are completed, they are expected to add meaningful production of subsequent revenues in 2012.

Additionally the Skogen 17-20 31H well is scheduled to begin completion initiatives in June, and we have a 6.6% working interest and a 5% NRI in this well. Lastly in the inventory, the Kepner 9-4 #1H well reached a total depth of 20,700 feet this week and completion initiatives are scheduled for June. We have a 4.6% working interest and a 3.6% NRI in this well.

Looking forward, it is anticipated that by mid-summer of 2012, that we will have an initial well drilled in all of our participated units in the Yellowstone AMI, and will therefore hold all of that acreage by production as a result. Zavanna has also indicated that they are working towards adding a Nabors rig to continue to drill the remaining undrilled unit in the SEHR acreage block through May of 2013.

In January 2012, we sold an undivided 75% of our undeveloped acreage in the SEHR prospect and the Yellowstone Prospect to GeoResources Inc and Yuma Exploration Production Company for $16.7 million. Our working interest in the remaining locations will be approximately 8.75%, and net revenue interest in new wells after the sale are expected to be in the range of 6.7% to 7%, proportionately reduced depending on Zavanna's actual working interest percentages.

This divestiture was done in order to maintain a strong financial balance sheet, and demonstrate our participated value in the program to the markets, as well as our shareholders. Pertinent to this sale, we did not sell any interest in two wells that we had previously drilled with Murex or eight high interest wells that had already been drilled or completed with Zavanna. In addition to our core acreage in North Dakota, the Company disclosed in our 10-K filing that during the course of 2010 and 2011, we acquired 100% working interest in approximately 25,000 gross, 18, 700 net, mineral acres of leases in Northeast Montana. At this time, we are seeking to partner with an industry peer to test the acreage in 2012 and implement a development program, if initial drilling results are successful.

I'd now like to move on to our drilling program in the oil window of the Eagle Ford Shale. In 2011, we entered into two participation agreements with Crimson Exploration to acquire an interest in two oil prospects in Zavala and Dimmitt counties, located in Texas. Under the two participation agreements, we participate as a 30% working interest, 22.5% net revenue interest partner, in 13,785 gross, 4,136 net, acres and two acreage blocks. The Leona-River Prospect and associated leases are located in Zavala County, Texas; and the Booth-Tortuga leases are located in Zavala and Dimmitt counties.

The leases in the Booth-Tortuga Prospect are currently held by production and produce approximately 115 gross BOE per day, 20 net BOE per day, from the Austin Chalk formation. The initial well in the Leona-River prospect, the KM Ranch #1 well, was drilled during the second and third quarters of 2011 and is now producing approximately 119 gross BOE per day. The well is still producing from natural pressure and has not yet been put on pump.

We have also drilled a second well on the acreage block, the KM Ranch #2 well. This well has been drilled to a total measured depth of 12,875 feet, including a 6,100-foot lateral, and is currently awaiting completion. The completion of the well is currently on hold until flow back of the Beeler #1 well results can be further evaluated, in order to help determine best practices for the potential development of the two programs. Crimson is also monitoring the results from a large operator that has a significant drilling program in close proximity to our activity, which has multiple well completion results pending.

The initial well in the Booth-Tortuga prospect, the Beeler #1 well, commenced production in mid-February at a gross 24-hour initial production rate of 370 BOE per day, or 337 barrels of oil and 195,000 cubic foot of natural gas on an 18/64th choke. The well was drilled to a total measured depth of 14,428 feet, including a 7,200-foot lateral, and was completed using 20 stages of fracture stimulation. At this time, we continue to monitor the initial flow back results of the well.

In addition to our Williston Basin assets, the Company participates with several different operators in the US onshore Gulf Coast region. At December 31, 2011 we had 5 gross, 1.12 net, producing wells in the region. Two of our wells with PetroQuest Energy have been very strong producers for the last several years, averaging approximately 300 BOE per day during this period. These wells were anticipated to produce for an approximate five-year well life and are now entering the end of their economic production cycle.

To counter this loss of production from the region, we drilled four gross wells during 2011 and had one gross well in progress at year-end. The LL Bean well, which the Company has an approximate 17% working interest and an approximate 13% net revenue interest is operated by PetroQuest Energy and began producing in the second quarter of 2011. The Company is currently realizing an average of 75.5 BOE per day from the well, which is primarily gas. The Bayou Bend well, which is operated by Southern Resources and was in progress at year-end, is currently being tied into production this month after a minor delay due to permitting.

Turning to the other areas of our Business, our nine building, 216-unit multi-family apartment complex averaged 87% occupancy during 2011 and realized average monthly revenues of approximately $174,000 during the period. The property is collateralized with a $10 million conventional note, and an impairment of $3.1 million was recorded to reflect the difference between the cost of the property and the lower range of its estimated fair market value at December 31, 2011. Although the property produces positive cash flow from its operations, the returns from our oil and gas investments are expected to yield a higher return, and therefore, it is our goal to sell this property in 2012 and redirect the sale proceeds to our growing oil and gas portfolio.

I would now like to discuss the status of our Mount Emmons molybdenum project, which is located in Gunnison County, Colorado. The Mount Emmons project is a primary molybdenum deposit which includes a total of 160 fee acres, 25 patented and approximately 1,353 unpatented mining and mill site claims, which together approximate 9,920 acres, or over 15 square miles of holdings.

In late December, 2010, we received a $1 million option payment from Thompson Creek Metals for 2011. In April 2011, Thompson Creek then notified the Company and terminated its option agreement with US Energy to develop the project. In notifying the Company, Thompson Creek cited more immediate development priorities in its portfolio. While we were disappointed with Thompson Creek's departure from the project, we were very pleased to have had the opportunity to work with Thompson Creek on this project. They were a first-class partner and we appreciate the work that they completed to advance the project.

Looking forward, we are now utilizing the numerous technical, engineering, sighting and cost studies that were completed during their involvement with the project to draft our mine plan of operations, which we expect to submit to the US Forest Service in the first or second quarter of 2013. We remain committed to moving the project forward on our own behalf, as well as reaching out to other potential partners in due course, as the mine plan of operation nears completion.

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

Thank you, Keith.

Looking at the year ended December 31, 2011, our operating revenues increased by $5.4 million, to $30.1 million, when compared to revenues of $24.7 million in 2010. The operating revenues increase is primarily due to higher commodity prices and a net decrease of $1 million in the loss recorded from our hedging activities, from $1.9 million in 2010 down to $900,000 in 2011. Operating revenues for 2011 reflect a 22% improvement from operating revenues realized in 2010.

Oil and gas operations produced operating income of $4.6 million during 2011, as compared to $8 million during 2010. The decrease in earnings from our oil and gas operation was primarily due to a $5.4 million increase in operating expenses, mainly caused by a $3.1 million work-over on one well and an increase of $3.4 million in depletion costs. These increases in costs were partially offset by an increase in revenues of $4.4 million and a $1 million decrease in unrealized and realized gains and losses on risk management activities, when comparing the year ended December 31, 2011 to the year ended December 31, 2010.

Our fourth quarter production revenues were $8.8 million, an increase of $400,000 over the third quarter of 2011. Due to the recorded $3.3 million loss from our hedging activities during the quarter ended December 31, 2011, operating revenues decreased by $2.9 million, to $7.1 million during the quarter ended December 31, 2011, as compared to revenues of $10 million during the quarter ended September 30, 2011.

The decrease was partially offset by an increase of $400,000 in production revenue. Our production volumes for the year ended December 31, 2011 averaged slightly over 1,212 BOE per day, which is a small decrease from 1,230 BOE per day in 2010. Our average realized price of $69.98 per BOE was an increase of $10.83 per BOE during 2011, when compared to the realized price of $59.15 from 2010.

Additionally, during the year ended December 31, 2011, we made the decision to sell our multi-family complex in Gillette, Wyoming, Remington Village. As a result of this decision, the operations of Remington Village were moved to discontinued operations, and an impairment of $3.1 million was recorded against the book value of Remington Village during the year ended December 31, 2011.

The operations at Remington Village for 2011 recorded a net income of $434,000 net of taxes, compared to a net income of $226,000 for the year ended December 31, 2010. The primary reason for the increase in net income for 2011 was the non-recording of any depreciation charges for the year ended December 31, 2011, due to Remington Village being recorded on our balance sheet as an asset held for sale. Primarily as a result of the activities described above, we recorded a net loss of $4.8 million, or $0.18 per share, during 2011, as compared to a net loss of $772,000, or $0.03 per share, for 2010.

Moving over to the balance sheet, on December 31, 2011, our total assets were $162.4 million, cash and cash equivalents were $12.9 million, and we had a debt balance of $12.4 million on the balance sheet, and an additional $9.9 million in debt that is recorded as a part of the liabilities held for sale. Our total debt at December 31, 2011 was $22.3 million, which was comprise of $12 million on our credit facility, $9.9 million related to Remington Village, and $400,000 related to our land at our mining operations in Colorado.

In January 2012, we paid the $12 million outstanding balance on our oil and gas facility down to zero. The $9.9 million debt related to Remington Village will be paid when Remington Village is sold. In summary, our balance sheet remains strong at December 31, 2011, with working capital of $16.2 million. We had a cash balance of $12.9 million, plus marketable securities of $166,000 at December 31, 2011.

Looking into 2012, we have our working capital position, the full amount of our $28 million in credit facility, and our cash flow from operations available to continue our funding and our continued growth in investment in our oil and gas portfolio.

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

Thanks, Bryon.

In closing, I'd like to point out that 2011 was a successful year for US Energy in terms of advancing our strategic -- our strategy in achieving meaningful growth in the E&P sector. We realized significant revenue from stabilized production in the Bakken, and we grew our reserves significantly by adding proven undeveloped locations in our reserve (inaudible). We added outlying acreage in the Williston Basin at reasonable costs, and at the same time we monetized acreage in the Basin in order to maintain our strong balance sheet, as well as demonstrate value to our shareholders. We also expanded our initiative into the oil window of the Eagle Ford play with Crimson, which could have significant development potential if our initial three well testing program performs as we anticipate.

As demonstrated in our recent sales, we will continue to prudently manage our balance sleet to maintain our flexibility in acquiring additional assets and to drive growth for our shareholders. 2012 promises to be another great year for the Company. We appreciate your support through 2011, and look forward to reporting results as they are achieved throughout the balance of the year.

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

Yes, sir. (Operator Instructions) Our first question comes from the line of Noel Parks from Ladenburg Thalmann.

Good morning.

Good morning, Noel.

Just a couple things. Sorry if I missed this, did you talk about what the dry hole cost was for that Oakville well?

We did not. Which well was it?

At Oakville, it was--

I think it was in the neighborhood of $300,000 to $400,000, Noel.

Oh, okay.

I can check that for you, though.

Okay. So, not a particularly large number.

No, it wasn't.

And also, just in the Eagle Ford, can you talk a little bit more about what's going on there as far as the fracking. It sounds like maybe there's some study going on as far as the technique or the recipe to use?

Yes. Noel, what we've been talking with Crimson about is, obviously we want to maximize potential of the field. We know we've got oil there, which is a positive, and there are different fracking techniques that are being applied by different operators in the area.

Chesapeake is one of the big ones that is literally right up against some of our acreage. And we are anticipating them completing those wells in the near future, possibly over the next quarter, and would like to see the results of those, as well as determine if their fracking technique is similar to ours or different than ours. If it's similar and they are getting good results, then we will continue where we're at. If they've changed it somewhat, then we would like to change it, if they are getting better results than we are.

Got you. And just the last thing I had is, any sense of going into this year what the G&A expense trends will look like?

I think that included in last year, we did see a decrease in some of the G&A, and we're working every day to cut costs wherever we can. So I would hope that the trend will continue, and we can reduce our G&A again similarly, like we did in 2011.

Great. That's all I had.

Thank you, Noel.

Thank you. And we also have a question from the line of Jeff Hayden from Rodman & Renshaw.

Hello, gentlemen. This is actually Adam Fackler.

Hello, Adam. How are you doing?

I'm doing well, thanks. I was hoping you might share with us from a strategic standpoint how you were thinking about M&A. And a little more specifically, is there a specific portion of the budget you're looking to reallocate, are there areas you would be particularly interested in? And finally along the same lines, assuming a transaction, would you ideally like to take an operating role or enter as a non-op?

Adam, we've discussed all of those options. We attended NAPIER a couple weeks ago, as well as have investigated numerous companies, as well as numerous projects. And to answer your question directly, obviously we're looking for oil, not necessarily gas. You'll probably see much less exploration for gas in our portfolio. We're looking for oil.

We saw several prospects -- we've taken a look at several prospects of old fields that are being redeveloped with laterals. We've actually looked at companies as possible acquisitions, as well. So, if we do go into operations, it will probably be from the acquisition of a smaller company, possibly private, possibly public, that has operations and it has some potential properties out there. And specifically, obviously, we probably will not spend the $25 million we have budgeted for the Eagle Ford this year, and so we are looking for ways to take that portion of our budget and reallocate it into the many prospects that we've been looking at.

Excellent. I appreciate it.

Okay. Thanks, Adam.

Thank you.

Thank you, sir. And our next question comes from the line of Jeff Connolly from Sidoti.

Hello, guys. I was just wondering if you could comment on the market for services and take-away capacity in the Williston Basin, and your expectations for the price differentials in 2012.

My understanding right now is we're seeing between $15 and $20 differential. And again, what I've been reading is there's a refinery in the Midwest that went down that had a capacity of some 110,000-barrels per day, and then conversely, they had a tar sand facility in Canada that also took away that capacity. But in any play like this, that is remote like the Williston Basin, it's going to have some growing pains and the take-away capacity is going to have to be added.

The last I heard is, EOG is trying to add another 50,000-barrel a day unit train to go down to Cushing. The good thing for us is we're seeing $105. So, at least we're realizing some $85 $90 a barrel. But I think that you're going to see additional and then -- there will be additions of capacity, and then as the play grows and if, again to answer your other question, if service costs don't escalate too much, because we have seen them, we're seeing AFEs as high as $11 million.

And again, maybe to anticipate some others, when you get EURs initially in remote areas like we have in SEHR and the Yellowstone areas, our engineers are giving us lower EURs. And then as the wells perform, they become better. So, the economics looks better, even on an $11 million well. That's part of the reason why you saw a increase in our PV10, although we sold our proven undeveloped locations, is because of the escalating costs. The drilling costs are staying fairly reasonable. The completion costs and the fracking costs have -- we have seen a significant escalation.

Now in relation to the same thing, I talked to the folks at Brigham and they're starting to see some of the competition get more competitive up there. And in fact, a couple of the recent AFEs we've seen from them, we have seen a slight decrease. So, it's one of those boom plays that if services get out of hand and then as prices come down and competition comes, it gets more competitive. So, that's kind of where I see it.

Okay. Thank you very much. And then, can you also comment on the timeline of the Eagle Ford program?

Well again, the oil is not going any place. Obviously, it's not going to get out of the ground until it gets fracked. And we just want to be sure with Crimson that we're using the very best techniques to maximize the potential. So I would say that we won't frac the KM Ranch probably for another month. We continue to monitor the flow back from the Beeler well. And so obviously, that program will be slowed down. To give you definite numbers, right now I can't tell you, because we still have to see the performance of these other wells and then judge how we're going to move forward.

Okay. Thanks a lot guys.

Thanks, Jeff.

Thank you. (Operator Instructions) We also have a question from the line of Joel Musante from CK Cooper & Company.

Hello, guys. Most of my questions were answered, but I've still got a few more. What's your current production right now, or the latest that you can give me?

Joel, you know, I asked Steve Richman about that this morning. They're skewed numbers, because we just completed a high two wells. So, it would be skewed currently, but probably somewhere in the 1,600 to 1,800 barrel. But that's going to -- those come down strong, Joel, so I want to caution you.

Right, right. So like before you brought on those wells, you were still in the same 1,100 to 1,200 barrel a day range, or --?

That's true, Joel. It was similar to year-end and similar to what we saw last year, 1,200 barrels.

Okay. And you brought on one of those wells in January, is that correct, and one in later?

Yes, the Kaliel came on in January, and then we just brought on the Lloyd, and then we're just drilling out the Wang.

Just drilling out the final bugs on the Wang here, Joel.

Okay. And then how long was the Beeler well, about a month?

The Beeler well has been on since clear back in November, Mark.

No, that was the KF-1. Beeler was mid-February.

February.

Okay. And you had a tax benefit of about $3 million. Was that from the write-down of Remington?

That was definitely a part of it, but there's also some benefit based on the excess depletion costs that we can get for 2011 versus carrying it out into the future.

Okay. And then just lastly, I was just looking at your -- some of the reserve information in your 10-K, and it indicated that you had $36 million in future development costs, but then there was $42 million of development costs, future development costs, in the standardized measure. What was the difference there? Was that proved developed producing dollars?

I think one of them is a PV10 and one of them is actual dollars. Joel, if you want to give me a call, we can get with Steve after the call, and I can maybe give you some clarification on that.

Okay. No problem. That's all I had.

Thank you, Joel.

Thanks, Joel.

All right. Thanks.

Thank you. Our next question comes from the line of George Gaspar, a private investor.

Yes, thank you. Good morning.

Good morning, George.

Hello, George.

First question, on the Eagle Ford. Just a little -- questioning the conclusions to date that there's a need to still try to figure out the fracking procedures. Considering the number of wells that Crimson has been involved in in the Eagle Ford already, I would think that they would have had the fracking procedures figured out for this particular area that you're joint with them on. Is there an explanation of what's different about that particular area you're in versus maybe other areas they're in? Because also, the flow back rates don't seem to be that high where you're involved currently.

George, the other areas they're in, in Karnes and Gonzalez are deeper, and they're more of the wet gas. The rock is different down there. Obviously, with the deeper depths, they have different depositions. So this is Crimson, and it's my understanding is that this is their first shallower, if you will, 6,000 foot depths, and so they are working on different fracking techniques and trying to get the best bang for the buck.

I see. And what about -- is there something unusual about the flow back procedures involving what has been done to date? I know it seemed like you ran into this problem on that very first well that you drilled in the Eagle Ford before you started these other two wells. Is there something unusual about the structure that allows -- requires a larger flow back period?

I don't think so, George. I think that this area in northern Dimmitt County has not had the development like it has in Southern.

I see.

And I think what we're seeing there is the fracking techniques are being tested. Obviously, Chesapeake is spending a whole bunch of money, not only around us, but all over the entire region, and we would sure like to see it. The good thing is, it's similar to Brigham. It's having these bigger companies spend the money to figure it out, and then everyone kind of follows Brigham's lead. And we think that we're going to see similar situations like that in the Eagle Ford.

Okay. And then just an overview question. Looking back since just post the announcement and the sale of the uranium properties, the stock is selling at about 50% less than it was at that time, and yet there's been a lot of activity commitment into the real estate and into drilling. And you've made some nice progress in North Dakota, marginal progress elsewhere to date. So that there's been about at least three, four years, correct me if I'm wrong, but it seems like it's that long now. And what is it going to take to get US Energy back up track to at least area of market price that existed before you even started into the oil patch and the real estate?

I think it's going to be performance, George. I think that as we grow our reserves and our production that we will be recognized in the industry, as well as advance our Mount Evans project, which is probably one of the reasons why our stock has not done as I would have expected it to. There's so many unknowns in the mining.

There's not a lot of E&P companies that have a mine out there. And we're working on various ways to realize value there. But just keep our shoulder to the grindstone and keep increasing the reserves and growing like we did last year, I think that eventually we'll be seen by the market and we'll be rewarded. Our shareholders will be rewarded for the efforts that we're putting forth.

Okay. And then one last one, on your flow rate. There was a question prior to mine here on your current flow rates. And you've got probably a positive plus flow rate right now because of an initial flow back. If you look at this 12,000 [sic] barrel a day range, considering what you've done now in the sales of interests, can you give us an idea where you would see that 1,200- barrels a day being, let's say without moving the exploration program forward from where it is now -- or completions.

In other words, I guess what I'm driving at is, what's the loss of production that's inside the text of the sales you have made, firstly, and secondly, what do you see in the decline curve against that 1,200 barrels a day?

Well, in the first sense, George, we didn't sell any of our production.

Okay.

(multiple speakers) -- as well as at the time, ten high interest wells going forward, of which we've completed now about five of those. So those wells keep our original ownership, as well as Brigham wells. Now to get to the crux of the question, understand that our first well we drilled with Brigham was in '09. And that was the Rattles #1 well, which is still producing and these wells are coming down somewhere between 100 and 200 barrels a day. And I think that the published numbers out there is a decline rate of some 3% to 5% after that, and the numbers seem to me to be working that out. So most of our base production, most of that 1,200 barrels, I see as being stabilized and will not be declining, if at all.

I see.

Complimenting that with the new wells that we're bringing on, even the smaller interest wells both with Brigham and Zavanna, the three we've got with Brigham that are planned, and I also feel confident they are going to give us more than the three this year, as well as the additional wells with Zavanna. So we don't give direction, George, but certainly, I could see us increasing our daily average production this year.

Okay. And one last one on real estate. What's the value that you're carrying the project at now? You took a $3 million charge, so what is it valued at? $20 million, $21 million range, or less?

That's what it was prior, George, and we're down around right at $18 million.

18, okay. And the original cost on that was what, around $23 million, $24 million?

$25 million.

$24 million.

$24 million or $25 million. Okay. Thank you.

Thanks, George.

Thank you. And we also have a question from the line of William Marcellus, another private investor.

Good morning. My question relates to Mount Edmonds [sic], and if the project plan is accepted, say later in 2012, how long would it take to actually get the project under way, and what is the Company's annual costs before actual development starts to carry the project?

William, this is Mark. And to begin with, our annual cost, including the water treatment plant and our projected cost for the year, is about $2 million. And of that, $1.8 million is roughly for the water treatment plant, and the other $200,000 is working on the mine plan of operations.

All of the technical data that we received from Thompson Creek was basically completed in the form of a pre-feasibility study, and we're moving that forward to draft the plan of operations, and we expect to file that -- submit the plan of operations to the Forest Service by April of 2013, at the latest. From there, a permitting timeline, there are a lot of uncertainties there, but we believe it's going to be a minimum of four years, is likely what we're projecting, to take it through the NEPA process.

And so then, during that four years, you would still be expending about the $2 million a year?

That is correct. It may be a little higher with other work and public outreach and so forth, possibly up to $1 million, to be conservative.

Okay. Thank you very much.

Thank you, William.

Thank you, sir. And I see no further questions from the phone.

All right. Well, ladies and gentlemen, thank you for joining the call. Thank you for all of the support from our shareholders and investors out there, and for keeping an eye on us. And we do look forward to an exciting 2012, and we look forward to updating you after our next quarter.

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