U.S. Energy Corp. (USEG) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Ali and I will be your conference operator today. At this time, I would like to welcome everyone to the U.S. Energy Corp. First Quarter 2012 Highlights, Operational and Financial Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Mr. Reggie Larsen, Director of Investor Relations for 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 who will be conducting the main portion of today's call; Mark Larsen, President; and Bryon Mowry, the Principal Accounting Officer for the company who will be reviewing the financial section of today's call. In terms of an agenda, we will provide you with an update on our operating initiatives for the quarter ended March 31, 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. 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 U.S. Energy’s management. These and all statements other than statements of historical fact are forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 and Section 27A of the Securities Act of 1933. The forward-looking statements are subject to numerous risks and uncertainties including those described in the Form 10-Q for the quarter ended March 31, 2012 which we filed on May 10, 2012, our Form 10-K for the year ended December 31, 2011 and our 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.

Thank you, Reggie, and good morning ladies and gentlemen. I will begin the call with an overview of our quarter ended March 31, 2012 operational highlights. On March 31, 2012 the company had 45 gross, 13.65 net producing wells which include: 27 gross Williston Basin wells, 5 gross Gulf Coast wells, 11 gross Austin Chalk wells in our Booth-Tortuga prospect and 2 gross Eagle Ford wells. The company produced 112,036 BOE during the 3 months ended March 31, 2012 with average daily net production during the quarter of 1,231 BOE per day. In the Williston Basin under the Brigham/Statoil program we completed 2 gross, 0.41 net wells. The Kalil #2 well was completed in January of this year and had an initial production rate of 1,654 BOE per day. The company has an approximate 27% working interest and approximate 21% NRI in this well. The Lloyd #2 well was completed in early March and had an initial production rate of 4,300 BOE per day, representing the highest initial production rate from any of our wells in the Williston Basin. We’ve an approximate 14% working interest and an approximate 11% NRI in this well. Subsequent to the quarter end, a third infill well in the state unit has been drilled to depth and has been fractured stimulated with 38 stages. The operator expects to drill out plugs and flow back the well to turn it over to production in July 2012. Our Three Forks well in this same unit is scheduled to be drilled in the fourth quarter of 2012, which will be the second Three Forks formation well drilled in our program to date. One additional infill well in The Hovde unit is also scheduled to be drilled in the fourth quarter of 2012. Drilling in completions also continued under the Zavanna program during the quarter and is scheduled to continue at an aggressive pace. During the quarter, we completed 2 drills 0.45 net and drilled 3 gross 0.25 net wells in the Yellowstone and SE HR prospects respectively. As we announced last week, the initial production rate of the Skorpil #1 well was 1,533 BOE per day on the 36/64" restricted choke; the well was fracture stimulated with 35 stages and began producing in late April. The company has an approximate 23% working interest and approximate 18% NRI in the well. The CDK #1 well has also been drilled to depth and fracture stimulated with 35 stages. The operator expects to drill out the plugs and flow back the well and turn it over to production in July 2012. The company has an approximate 32% working interest and approximate 25% NRI in this well. The Larsen #1 well has also been drilled to depth and is currently being fracture stimulated with a planned 35 stages. The company has approximate 28% working interest and an approximate 21% NRI in the well. I would like to point out that the above mentioned wells all have high net interest to the company and they are anticipated to add meaningfully to our daily production as they are brought on line. Three additional wells are currently drilled to depth and are scheduled to be fracture stimulated between now and July of 2012. The Skogen #1 well is scheduled to be fracture stimulated in late May. The company has an approximately 6.6% working interest and approximate 5% NRI in the well. The Kepner #1 well is scheduled to be fracture stimulated in June. The company has an approximate 4.6% working interest and an approximate 3.6% NRI in this well. The Wells #1 well is scheduled to be fracture stimulated in late June. The company has an approximate 9.1% working interest and approximate 7% NRI in this well. Looking forward, we’re anticipating having an initial well drilled in all of our participated Yellowstone acreage units and therefore hold all units by production by mid-summer 2012. The operator will then focus on drilling the remaining SE HR initial wells units through May of 2013. Before moving on from our Zavanna program, I would like to note that in January 2012 the company sold an undivided 75% of its undeveloped acres in its Yellowstone and SE HR Zavanna lease hold interest for $16.7 million and $1.4 million in reimbursed well cost. The company retained the remaining 25% interest in the undeveloped acreage and its original working interest and production in 10 gross, 2.3 net wells. Our average 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%. Moving onto our Daniels County Montana acreage, on May 9, 2012 the company signed a letter agreement to sell an undivided 87.5% of its acreage to a third party for $3.68 million. The agreement is condition upon execution of the mutually acceptable purchase and sale agreement and will be effective on June 1, 2012. Under the terms of the agreement, the company will retain a 12.5% working interest in the acreage and reserved overwriting royalty interest. The purchaser also committed to drill a vertical test well to depth sufficient to core the Bakken and Three Forks formation on or before December 31, 2015. The company will de-lever an 80% NRI to the purchaser and 1% overriding royalty interest to a land broker. The company will also pay the land broker a 10% commission for the cash consideration paid by the purchaser upon the closing of the transaction. In addition to our success in the Williston Basin, the company has a 30% working interest in 2 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 2 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. During the quarter, we drilled and completed one gross well, 0.3 net which is the initial test well at the Booth-Tortuga prospect. The Beeler #1 well commenced production in mid-February at a gross 24 initial rate of 370 BOE per day on at 18/64 choke. The well was drilled to the total measured depth of 14,428 feet including 7,200 foot lateral and was completed using 20 stages of fracture stimulation. The company has an approximate 30% working interest and 22.5% NRI in this well. The KM Ranch #2H well in Zavala County, our second well in the Leona-River acreage block, was also drilled during the quarter to a total measured depth of 12,875 feet including a 6,100 foot lateral and is awaiting completion. The operator continues to monitor specific completion activity methods and performance of the surrounding area in order to develop a more effective completion for optimum recovery and its high potential environment. The operator has not yet scheduled the completion of the KM Ranch #2 as we both believe that it is more important to first develop the best practices setup procedures for completion in the region that will maximize our return on investment. We are also monitoring recent activity of other operators in other formations in the Dimmit County area that could increase the upside potential for our position there dramatically. All acreage in both areas are held by production. The Bayou Bend well located in the Southeastern Texas was also drilled by Mueller Exploration during the third quarter of 2011. The well was drilled to a depth of 11,265 feet and 3 prospective pay zones were encountered. The well targeted a liquids-rich gas formation. The well began sales in April 2012 and had initial flow back rates of approximately 200 BOE per day which consisted of approximately 80 barrels of oil and 700 MCF of natural gas. The company has an approximate 13.5% working interest and a 9.9% NRI in this well. I would now like to provide a brief update on our Remington Village Apartment complex located in Gillette, Wyoming. Mid-April, Colliers International commenced their marketing effort for Remington. Thus far we have received a very encouraging response. We have a $10 million long term loan from a regional commercial bank on the asset which will be satisfied in full upon the completion of the sale. Our goal remains to monetize this asset in order to maintain our focus on oil and gas and deploy the remaining capital into our active drilling programs. We expect to complete the sale of Remington this year. Finally, before turning the financial portion of the call, I would like to provide an update on the Mount Emmons Project. As we announced yesterday, we’re in the process of developing a world-class molybdenum deposit in Gunnison County, Colorado known as Mount Emmons Project. As a result of several meetings held with interested local parties and numerous public officials over the course of the last year, we have determined that we will consider land exchange or similar process that would allow the conveyance of the patented and unpatented mining claims associated with the Mount Emmons Project to the United States in return for real property or other consideration. The potential land exchange will proceed in parallel with U.S. Energy’s ongoing effort to secure permits for the development of its Mount Emmons molybdenum mine. In June 2011, U.S. Energy met with the town of Crested Butte and other interested parties to determine whether there were alternatives to full mine development. High Country Citizens’ Alliance and Red Lady Coalition, opponents of mine development, also participated in the process. After a serious of conversations, U.S. Energy agreed to explore the possibility of a land exchange. U.S. Energy currently operates a water treatment plant to treat legacy water discharge from a prior mine on the Mount Emmons property. The town parties are exploring the formation of a special district to take over operation the of water treatment plant. Assumption of the water treatment plant by a third party is a fundamental pre-condition to consummating a land exchange. Conversations with the town of Crested Butte, other state and federal government officials and local public interest organizations are ongoing and U.S. Energy has found substantial support for the proposed exchange. However, the potential exchange remains subject to legislative action as well as a federal appraisal. U.S. Energy intends to work closely with Colorado senators Michael Bennet and Mark Udall in the near term to see legislation introduced in the U.S. senate. The Board of U.S. Energy has put several conditions on any consideration of an exchange as follows: that the company pursue the exchange contemporaneously with permitting efforts for full mine development; that the land exchange be substantially completed by year end 2012; that a third party entity takeover the operation of the water treatment plant located at the Mount Emmons property; and that the company receives significant value for its shareholders as part of the exchange. During the course of 2011, U.S. Energy conducted extensive due diligence concerning the potential land exchange. As part of that process, U.S. Energy engaged a private consulting group to assist us in the land exchange diligent process. U.S. Energy has also had a series of meetings in Washington D.C. to discuss legislative approaches to the land exchange. In addition, U.S. Energy engaged a federally certified appraiser to provide the company with a preliminary assessment of the value of the Mount Emmons properties using federal appraisal standards. Preliminary evaluation came in at a range of $50 million to $100 million in value today utilizing various valuation approaches similar to a commercial appraisal. Final valuation of the Mount Emmons properties would be based on a federal appraisal which would be completed sometime in future based on legislative actions. It should be noted that the federal appraisal may vary substantially from the preliminary appraisal commissioned by U.S. Energy. Furthermore, it is possible that U.S. Energy and the State of Wyoming could work together to exchange Mount Emmons and certain state-owned lands within the boundaries of Grand Teton National Park in Wyoming to the United States to a joint exchange legislation. Such an exchange could also result in compensation for the State of Wyoming for its parcels inside Grand Teton National Park. While the operating process between the State of Wyoming and U.S. Energy remains in the early stages of assessment, both parties recognize that a joint exchange could provide broader benefits to all parties. We have dedicated considerable time over the last year investigating a land exchange as a possible method for us to create shareholder value for the Mount Emmons project in the nearer term. However we will continue to work on the plan of operations for the Mount Emmons mine, which we plan to submit in the first quarter of 2013. The stool path approach provides us with time to continue to gauge the likelihood of the federal land exchange while preserving our rights to advance the project towards the permitting process and the resumption of our project marketing efforts at the beginning of 2013. We appreciate the efforts of Colorado Senators Bennet and Udall and look forward to continuing to work closely with them and the town parties as this endeavor progresses in the coming weeks and months. All parties understand that we have a window of opportunity to make something happen this year in regards to a federal exchange and we will remain committed to this effort through the balance of 2012. 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. Operating revenues increased by $1.7 million to $8.3 million during the quarter ended March 31, 2012 as compared to revenues of$ 6.7 million during the quarter ended March 31, 2011. This is an increase of 24.8% when comparing the first quarter of 2012 to the first quarter of 2011. The operating revenue increase is primarily due to higher oil sales volumes and higher average commodity prices. Operating revenues for the first quarter of 2012 do reflect the decrease of $500,000 when compared to operating revenue realized during the fourth quarter of 2011. The decrease is primarily due to slightly lower production during the first quarter of 2012. Production volumes for the 3 months ended March 31, 2012 averaged approximately 1,231 BOE per day, up 9.6% from the first quarter of 2011, but a decrease of 4.6% in production volumes from the fourth quarter of 2011. Our average realized price of $74.40 BOE, was $8.33 BOE higher during the first quarter of 2012 than realized prices from the first quarter of 2011, but down approximately $0.15 BOE from realized prices in the fourth quarter of 2011. Operating income from oil and gas operations was $1.8 million during the quarter ended March 31, 2012 as compared to a operating loss of $185,000 from oil and gas operations during the quarter ended March 31, 2011. The increase in earnings from oil and gas operations is primarily due to: a $1.7 million increase in revenues due to higher production and commodity prices during 2012 when compared to 2011; and a net decrease of $1.2 million of lease operating expenses. The increase in oil and gas revenue and the decrease in operating expenses were partially offset by $856,000 higher depletion expense in 2012. Direct operating income from oil and gas operations increased by approximately $2 million from the 3 months ended March 31, 2011 and increased by $60,000 when compared to the 3 months ended December 31, 2011. Our DD&A rate was approximately $32.50 per BOE for the first quarter of 2012 as compared to $27.55 BOE for the first quarter of 2011 and $35.65 for the fourth quarter of 2011. A 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 proved reserve volumes and estimated cost to drill and complete proved, undeveloped reserves. The drop in the DD&A rate from the fourth quarter of 2011 to the first quarter of 2012 was partially a result of a sale of a portion of our undeveloped acreage in December 2011 and January 2012. Our lease operating expense per BOE including workover costs was $25.82 for the 3 months ended March 31, 2012. This rate compares to $40.34 per BOE for the quarter ended March 31, 2011 and a rate of $24.23 for the quarter ended December 31, 2011. The main reason for the decrease in the LOE rate when comparing quarter to quarter is that during the quarter ended March 31, 2012 we had $718,000 in workover expense which was $1.8 million lower than the quarter ended March 31, 2011. When comparing the first quarter of 2012 to the fourth quarter of 2011, our LOE rate has increased $1.59 per BOE. The main factor in that is an increase of $431,000 in workover expense during the first quarter of 2012 compared to the fourth quarter of 2011. During the quarter ended March 31, 2012 we recorded a net loss of $381,000 after taxes or $0.01 per share as compared to a net loss after taxes of $2.2 million or $0.08 per share for the quarter ended March 31, 2011. During the fourth quarter of 2011, we recorded a net loss of $2.8 million or $0.07 per share. Our balance sheet remained strong at March 31, 2012 with working capital of $11.8 million including cash and cash equivalents of $7.8 million. On March 31, 2012 we had a total debt balance of $10.2 million primarily related to our Remington Village project. On May 1, 2012 we borrowed $5 million from our senior credit facility with the proceeds of the loan being used to fund our oil and gas program. In March 2012, our borrowing base under the senior credit facility increased from $28 million to $30 million as a result of the re-determination based on the December 31, 2011 financial statements, production reports and reserve reports. Currently we have drawn down $5 million on the line of credit. On April 20, 2012 Wells Fargo completed the purchase of BNP Paribas North American reserve-based oil and gas lending group. The personnel involved with our senior credit facility joined Wells Fargo as a result of the sale by BNP Paribas and our borrowing base facility is now officially been transferred to Wells Fargo. I would like to turn the call back over to Keith Larsen for the Q&A session.

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

[Operator Instructions] Your first question comes from the line of Noel Parks of Ladenburg Thalmann.

Just a couple of things. Thinking about the rest of the year in production, it sounds like there is some sort of clustering of when you expect especially Bakken wells to come online, the completion is in June-July. Is it likely that the third quarter production might be a little softer than the second quarter and then fourth quarter would be good bit stronger or do you expect more of steady increase throughout the year?

Noel, as you know, we get the initial flow backs from the high interest wells which we are not going to be participating in, in the third and the fourth quarter, they would be lower interest wells, but we do anticipate participating in several additional wells specifically with Zavanna. We don't give guidance on what the rest of the year is going to be, but I could see an increase and we still expect to exit the year better than 1,500 barrels a day.

Okay, great. You mentioned in the Eagle Ford, I think you said in Dimmit County, you had a couple of other formations that you are aware of other operators having a look at. Could you talk a little more about that?

Yes. Both the Pearsall and the Buda, we have heard that they are trying some laterals in both formations and have had some encouraging results, and of course we do have both the Buda and the Pearsall in both areas. So as well as watching the completions in the Eagle Ford by several operators, one specifically being Chesapeake that has around 15 wells very near our Leona-River prospect, we are watching for others and their production rates and so forth and we are hoping the play comes to us. Of course both areas are held by production and we'd rather other people spend their money and bring the play to us and we can learn as much as we can on all 3 of those formations and possibly others.

Okay and just one last thing in the financials. On a unit basis does the DD&A stabilize pretty much from here or -- just because you do have some pretty decent CapEx at this point in the year, or are we going to see some more fluctuation there as well?

Noel, what I'm seeing out there is starting to see a reduction in the price to drill and complete. We're seeing between $10 million and $11 million in AFEs, up from $6.25 million when we started the program with Brigham back in '09. But after talking with Brigham and Zavanna, both, we're starting to see a lot more competition, specifically in the completion. So hopefully that DD&A rate is going to come down some, and I think probably that will be echoed by other operators as well.

Your next question comes from the line of Jeffrey Connolly of Sidoti & Company.

Just looking at your balance sheet, you have a lot of flexibility and you've lowered the CapEx guidance by about $5 million, and it seems that Eagle Ford might be kind of coming along a little bit slower than expected initially. So can you comment on what other opportunities you might have to deploy capital and if you're thinking about anything else?

We're seriously looking at 2 additional projects. And the $5 million reduction was a result of our missing on the Cirque well that we drilled in California. We had $5 million budgeted for there and that's why we reduced it. If we do have a slowdown in the Eagle Ford, then we plan on pursuing another couple of deals that we're working on as we speak to deploy that capital in those areas.

Okay. And then, can you just add any additional comment on the land exchange and if the land that you'd be getting is prospective for oil and natural gas?

Specifically right now what we're looking at is lands that are associated with coal here in Wyoming. Although we don't know what the final land will be, we're pursuing several. We have not been looking at federal oil and gas properties to date, but various -- either credits from the U.S. government, bidding rights on anything, including oil and gas, or other ways to create value. And again, we think that we have broad-based support after the discussions that we've had both in Washington D.C., the State of Colorado and the State of Wyoming.

Our next question comes from the line of Joel Musante of C.K. Cooper, Incorporated.

I just had a couple of questions. In Dimmit County, I saw that Chesapeake reported some good well results in the Eagle Ford. Could you just comment on where those wells were with respect to your acreage and if there's anything else that you can add to that?

Well the one that I know of for sure, Joel, was the Lazy A Cotulla. I believe it was #3, and it's about 10 miles to the southeast of our prospect in Dimmit. The other well I wasn't able to find out where it was, but in all total around our area I’ve identified over 30 wells that are either being drilled and completed or have been permitted, that some are within a throwing distance of a rock of our property, and others 1 to 3, 4 or 5 miles away. So we and our partner, Crimson, are regulating and monitoring the results of those wells. And I've said this before to you, Joel, if the play comes to us and the money that's being spent -- I see it much like the Bakken where someone else spent their money to really figure it out and we're holding all of our acreage by production, so that when the play comes to us and they really get the final recipe, then that's the time to get more aggressive at it.

Okay. So, I mean, the rates that they had were quite a bit higher than what you had on your properties. I mean, is there a difference -- and I'm not sure if you know anything about their completions or anything, but, I mean, if you compare the well completions at the 2 locations, I mean, is there any…

Joel, as you and I have discussed, we believe that Chesapeake is using the same recipe that we used on the KM Ranch #1, which were encouraging. We plugged back 10 of the perforations and brought on a well of over 400 barrels. And by interpolation that would indicate that if we would have had the water issue with the other stages, it would have came in over 800, which I consider to be a good well. The well that we did with, in Dimmit County, they backed off with the pressures and the proppants that they used in that well in hopes of not fracturing into possibly the Buda or the Austin Chalk, where they thought the water was coming from. And of course, those results were not as encouraging. So I believe that Chesapeake is using the same fracture stimulation as we did on the KM Ranch #1. And if they are and are getting similar results that we had on that initial well, then that's probably the fracture stimulation job that we will do on the KM Ranch #2. Again, we're awaiting the results of those wells and as much information as we can get before we go ahead and frac that second well.

Okay and just one more. On the Brigham or Statoil now, wells, they were going to -- the payback period was going to kick in at some point. I was just trying to find out if that had kicked in already or if that's still off in the future or somewhere.

Well just as a reminder to everybody, on the Statoil deal, the deal that we made was we got paid back on all 6 of the first wells, and then they back in for 30% of our interest in those well bores. Then the next 4 as a group, we get paid back and they back in for 30%. And then the last 5, it's a well by well payback. Today, we've got 3 or 4 wells that have paid back. But because of a work over that we did on the Brad Olson #1, our very first well in the program, they're still a good distance out. I would say at least 12 to 24 months out before we'll receive payback on those first 6 wells. And then it may be that the second 4 pay back before the first 6 because of that significant workover on the brad Olson #1, but we are getting paid back on the wells. It's not as quick as we'd have anticipated because of some of the workovers and the jibs we've received, but they are paying back and we anticipate over the next 12 months to have payback on maybe 8 to 10 other wells in the program.

Our next question comes from Kurt Caraminidis of Carl M. Hennig, Inc.

It seems like, operationally, things are going pretty well. I've been an investor for a long period of time, yet the stock price is about half of book value, about the value of the molybdenum mine with no value for the oil assets, which is pretty unbelievable when I look around and see value-to-book, most of the companies doing what you're doing are selling at 1x to 2x book. I'm wondering what the plan is and what to do differently investor-relations wise? Some kind of a dividend if you're making money on selling assets, management? How do we explain the stock price with what looks to be operationally going well but stock price is unbelievable down here?

Kurt, we're frustrated as you are. I've attended the IPAA meeting in New York last month, continue to go out and visit with investors, doing non-deal road shows and we're frustrated like you. The only answer that I can give you, because I do get the same question, is that people see possibly the mine as a negative, which it is at this time. It's a $1.5 million to $2 million a year expenditure. We thought that by pursuing this land exchange that we could ease the minds of investors somewhat, as well as pursuing mine development. The other thing is, of course, selling our real estate. There's not a lot of oil and gas companies out there, so we're trying to clean up the other assets and become a pure oil and gas play. And we've had a 100% success in the Bakken. Every one of the wells that we've drilled have been successful. So again, we just keep bringing on the wells, increasing our production, increasing our reserves, and eventually I believe the market will catch up with us.

So no plan to change -- it's just hard for me to explain how things are going so well. And it's -- basically, I thought we had about $4 just in oil. So you're saying that molybdenum mine and the apartment is so bad that we're -- that it's taking the company down way below what the oil and gas is? I guess I would look for something new with investor relations, some kind of a dividend if you're making money on selling that land, or if we start making more on the oil and gas doing a regular dividend, because what we're doing is not working at all and it's quite obvious. But that's what I would hope for in the future.

Again, we'll note those suggestions. As far as paying a dividend, as you know, we didn't make money in the quarter. We lost a penny. But our next goal is to make money, and that's what we're working toward. As well as, as we've mentioned, we've taken $5 million of our line of credit, so we're not going to borrow money to either pay a dividend or possibly buy back stock. But your comments are well noted and certainly something new in investor relations, or a new approach or those type of things, we'll certainly take those suggestions under evaluation and we'll work toward that.

I appreciate it. And insiders, the lack of buying there, that might show some support. It appears as though it's one heck of a buy at this price, but I guess if there's not people in management stepping up to the plate, I don't know why anyone else would. But I'm just frustrated. I know operationally we're doing well, but thanks for taking my call.

Appreciate your frustration. We're with you and let me assure you that all of the employees at the company are working diligently to turn the balance sheet around, get us to making money, and get the stock price where it needs to be.

Our next question comes from Mike Jacobson of Oak Ridge Financial.

Gentlemen, I'm a stockholder. I'm also a licensed broker. My question specifically is to Mr. Keith Larsen. How do you justify using cashless exercise on your stock options rather than buying the stock outright?

That's a benefit that the Board of Directors gave me at the time. And at the time when you don't have the money to do that and you're going to lose the options, then that's the only avenue that's available to us.

So you have no investible money out of this nice salary that you're receiving?

That's pretty much it.

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

Yes. I'd like to end the call by saying that our drilling programs remain active this spring and moving into the summer months. We look forward to reporting our additional drilling and completion results that are currently underway. Under our Eagle Ford program with Crimson, we will continue to work with the operator to obtain additional production data, as well as information from active programs in the region of our acreage blocks to further delineate and understand the prospective area. If successful, this program could add significant development potential for the company going forward. I would also like to thank all parties involved in the collaborative efforts toward the advancement of the Mount Emmons project. We are pleased to be at a point to share our efforts of last year and the potential impact that this could have to our company. Internally, our President Mark Larsen and our General Counsel Steven Youngbauer have done an outstanding job to advance the effort to this point. There's much work left to be done before we get to the end game. And I assure you that we will continue to work diligently with all parties with the goal of finding a winning solution for everyone. I would like to thank our audience for joining us today, and we look forward to updating you on our next call. Good bye, everybody.

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