secltr.htm

January 3, 2013

Karl Hiller

Branch Chief

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-7010

Re:

U.S. Energy Corp., Form 10-K for the Fiscal Year ended December 31, 2011

Filed March 14, 2012 (File No. 0-06814)

Dear Mr. Hiller:

Set forth below are responses of U.S. Energy Corp. (the “Company”) to the comments of the Staff of the Division of Corporation Finance, which were delivered in your letter dated December 20, 2012 regarding the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (the “10-K”).

Set forth below are the Staff’s December 20, 2012 comments, indicated in bold, followed by responses on behalf of the Company.

Form 10-K for the Fiscal Year ended December 31, 2011

Business, page 7

Texas and Louisiana, page 12

We note your statement, “The KM Ranch #1H well… had an announced initial gross production rate of 418 BOE/D from 11 fracture stimulation stages.” The energy equivalency for oil and natural gas is six MCFG per barrel of oil equivalent (BOE) from page 126. In order to avoid confusion concerning the energy and price equivalency of oil and natural gas, please expand your disclosure of production rates to include the figures for oil and for gas.

Response:

The KM Ranch #1H well was drilled to a total depth of approximately 12,500 feet (~6,000 ft. vertical, ~6,500 ft. horizontal) by Crimson Exploration, Inc. at the Leona River prospect. It was completed in the second quarter of 2011 and had an announced initial gross production rate of 418 BOE/D (331 barrels of oil per day and 524 MCF per day) from 11 fracture stimulation stages.

Subject to the Staff’s comments, we propose to include both oil and gas production rates in all future production rate disclosures in our future Forms 10-K (beginning with our Form 10-K for the fiscal year ended December 31, 2012).

Properties, page 30

Proved Undeveloped Reserves, page 32

We note that you disclose your proved undeveloped (PUD) reserves as of the beginning and end of 2011 and indicate that some changes were due to the conversion of 79 MBOE to proved developed status. However, given that you had significant increases in PUD reserves, you should follow the guidance in Item 1203(b) of Regulation S-K which requires the disclosure of “…material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted into proved developed reserves.” Please revise your presentation to identify material changes of PUD reserves due to: revisions of previous estimates; improved recovery; acquisitions and divestures of properties; extensions and discoveries.

Response:

As of December 31, 2011, we had 980,696 BOE of proved undeveloped reserves, which is an increase of 773,769 BOE, or 474%, compared with 206,927 BOE of proved undeveloped reserves at December 31, 2010. The increase in proved undeveloped reserves is primarily due to drilling activity in and adjacent to our Bakken/Three Forks acreage. As a result of this drilling activity, our proved undeveloped reserve locations increased from 3 gross locations at December 31, 2010 to 29 gross locations at December 31, 2011. We invested approximately $4.6 million to convert 79,198 BOE of proved undeveloped reserves to proved developed reserves in 2011 in our Bakken/Three Forks properties. The following table details the changes in the quantity of proved undeveloped reserves during the year ended December 31, 2011:

		Proved Undeveloped Reserves (BOE)
January 1, 2011		206,927
Conversion to proved developed reserves		(79,198)
Revisions of previous quantity estimates		(13,381)
Extensions, discoveries and improved recoveries		952,112
Sales of reserves in place		(85,764)
December 31, 2011		980,696

Page 2 of 6

As of December 31, 2011, we have no proved undeveloped reserves that have been on the books in excess of five years and we have recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. Additionally, no proved undeveloped reserves are scheduled for development beyond five years of booking. As of December 31, 2011, estimated future development costs relating to proved undeveloped reserves are projected to be approximately $35.9 million over the next five years.

Subject to the Staff’s comments, we intend to include disclosure that is substantively consistent with the above disclosure in our future Forms 10-K (beginning with our Form 10-K for the fiscal year ended December 31, 2012).

We note your statement “As of December 31, 2011, we have no proved undeveloped reserves that have been on the books in excess of five years…”. Please tell us whether you have PUD reserves that are scheduled for development beyond five years of booking. You may refer to FASB ASC Section 932-235-20 Glossary for the definition of proved undeveloped reserves.

Response:

As of December 31, 2011, we have no PUD reserves that are scheduled for development beyond five years of initial booking. Subject to the Staff’s comments, we intend to include in our future Forms 10-K disclosure clarifying that we have no proved undeveloped reserves that have been on the books more than five years after the date they were initially booked.

Oil and Gas Production, Production Prices, and Production Costs, page 33

4.	The guidance in Item 1204(a) of Regulation S-K requires separate disclosure of production for an area containing at least 15% of your proved reserves. As such, it appears that you should disclose the annual production at your Williston Basin area in each of the last three years.

Page 3 of 6

Response:

The following table provides a regional summary of our production for the years ended December 31, 2011, 2010 and 2009:

	December 31,
	2011	2010	2009
Williston Basin
Oil (Bbls)	271,939	282,527	64,485
Natural gas (Mcf)	129,635	98,820	12,750
Natural gas liquids (Bbls)	--	--	--
BOE	293,545	298,997	66,610
Gulf Coast / South Texas
Oil (Bbls)	16,081	20,906	15,976
Natural gas (Mcf)	590,982	659,085	454,941
Natural gas liquids (Bbls)	19,325	19,104	5,987
BOE	133,903	149,858	97,787
Eagle Ford
Oil (Bbls)	4,290	--	--
Natural gas (Mcf)	8,479	--	--
Natural gas liquids (Bbls)	--	--	--
BOE	5,703	--	--
Austin Chalk
Oil (Bbls)	8,015	--	--
Natural gas (Mcf)	7,165	--	--
Natural gas liquids (Bbls)	--	--	--
BOE	9,209	--	--
Total
Oil (Bbls)	300,325	303,433	80,461
Natural gas (Mcf)	736,261	757,905	467,691
Natural gas liquids (Bbls)	19,325	19,104	5,987
BOE	442,360	448,855	164,397

Subject to the Staff’s comments, we intend to include tabular disclosure that is substantively consistent with the disclosure above in our future Forms 10-K (beginning with our Form 10-K for the fiscal year ended December 31, 2012).

Acreage, page 35

We note that your table of leasehold acreage does not include details of acreage and lease expiration. Item 1208(b) of Regulation S-K requires the disclosure of material acreage which will expire in the near term, e.g. each of the next three years. Please expand your disclosure to comply with this requirement.

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Response:

As a non-operator, we are subject to lease expiration if any operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there is no assurance that we can do so. The approximate expiration of our gross and net acres which are subject to expiration between 2012 and 2016 are set forth below:

	Williston Basin, North Dakota and Montana		Southeast Texas and Louisiana		Eagle Ford/Austin Chalk, Texas		San Joaquin Basin, California		TOTAL
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2012	5,099	866	1,281	173	-	-	1,241	496	7,621	1,535
2013	12,591	4,788	-	-	889	445	29	9	13,509	5,242
2014	16,220	11,094	-	-	2,392	1,009	3,320	1,122	21,932	13,225
2015	6,783	3,227	-	-	889	445	1,824	534	9,496	4,206
2016	1,920	770	-	-	-	-	45	17	1,965	787
	42,613	20,745	1,281	173	4,170	1,899	6,459	2,178	54,523	24,995

Subject to the Staff’s comments, we intend to include disclosure that is substantively consistent with the disclosure above in our future Forms 10-K (beginning with our Form 10-K for the fiscal year ended December 31, 2012).

Exhibit 99.2

On page 3 of the third party reserve report the average adjusted natural gas price used for reserve estimates appears as $8.16/MCF while the benchmark price is $4.118/MMBTU. However, on page 33 of your Form 10-K you disclose that your 2011 average historic received price was $4.85/MCFG. Please explain to us the adjustments you made to arrive at the $8.16 price used in your estimates.

Page 5 of 6

Response:

The $4.118/MMBTU price used in the December 31, 2011 reserve estimate prepared by Cawley, Gillespie and Associates is specific to our Bakken/Three Forks wells. The operators of these wells do not break out natural gas liquids sales separately. They combine all natural gas and natural gas liquids sales and report those sales back to us as natural gas sales only. Because the natural gas in this region is typically high BTU gas, the price that the operators report to us as natural gas sales is approximately double the first day of month Henry Hub price for natural gas. Based on actual historical sales prices, Cawley, Gillespie and Associates used a multiplier ranging from 1.962 to 2.149 for Bakken wells operated by Brigham Oil and Gas, L.P. Due to limited historical pricing information, Cawley, Gillespie and Associates used multiplier of 1.976 for Bakken wells operated by Zavanna LLC based on the average multiplier used for wells operated by Brigham Oil and Gas, L.P.

The remaining two reserve reports included in Exhibit 99.2 were prepared by Ryder Scott Company L.P. and Netherland Sewell and Associates, Inc. These reports cover our wells in Texas and Louisiana. Like the Cawley, Gillespie and Associates reserve report, both Ryder Scott L.P. and Netherland Sewell and Associates, Inc. adjust product prices for each property to

reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from the market. The average adjusted natural gas price used in the estimates for these reports is $4.15/MCF and $4.025/MCF, respectively.

The 2011 average historic received price of $4.85/MCF disclosed on page 33 of our Form 10-K is the average price received across all of our properties, including Bakken, Louisiana and Texas wells.

* * * * *

The Company acknowledges that:

·	it is responsible for the adequacy and accuracy of the disclosure in the filing;

·	Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

·	it may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Should you require further clarification of any of the issues raised in this letter, please contact the undersigned at (307) 856-9271. Thank you in advance for your assistance.

	Sincerely,

	/s/ Keith G. Larsen
	Keith G. Larsen
	Chief Executive Officer

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