US ENERGY CORP - Quarter Report: 2015 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

☒	Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended March 31, 2015 or
☐	Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ___________ to ____________

Commission File Number: 0-6814

U.S. ENERGY CORP.

(Exact name of registrant as specified in its charter)

Wyoming		83-0205516
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
877 North 8th West, Riverton, WY		82501
(Address of principal executive offices)		(Zip Code)
Registrant's telephone number, including area code:		(307) 856-9271

Not Applicable

(Former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer    ☐	Accelerated filer    ☒
Non-accelerated filer   ☐  (Do not check if a smaller reporting company)	Smaller reporting company ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

At May 5, 2015 there were 28,047,661 outstanding shares of the Company's common stock, $0.01 par value.

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U.S. ENERGY CORP. and SUBSIDIARIES

INDEX

		Page No.
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)
	Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	4-5
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014	6-7
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 and 2014	8
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	9-10
	Notes to Condensed Consolidated Financial Statements	11-26
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27-38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38-39
Item 4.	Controls and Procedures	39
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	41
	Signatures	42
	Certifications	See Exhibits

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PART I.  FINANCIAL INFORMATION

ITEM 1.  Financial Statements

U.S. ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
(In thousands, except shares)
		March 31,				December 31,
		2015				2014
Current assets:
Cash and cash equivalents		$	3,976			$	4,010
Available for sale securities			25				25
Accounts receivable trade			1,404				3,177
Other current assets			227				288
Total current assets			5,632				7,500
Oil and gas properties under full cost method,
Proved oil and gas properties			133,227				147,486
Unproved oil and gas properties			9,200				10,188
Exploratory wells in progress			368				2,357
less depletion, depreciation and amortization			(74,636	)			(71,762	)
Net oil and gas properties			68,159				88,269
Undeveloped mining claims			21,942				21,942
Property, plant and equipment, net of
accumulated depreciation of $4,441 and $4,404			3,879				3,942
Other assets			1,887				1,870
Total assets		$	101,499			$	123,523

 

 

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
(Unaudited)
(In thousands, except shares)
		March 31,				December 31,
		2015				2014
Current liabilities:
Accounts payable		$	8,879			$	7,441
Accrued compensation			483				441
Commodity risk management liability			63				--
Other current liabilities			79				84
Total current liabilities			9,504				7,966
Noncurrent liabilities:
Long-term debt			6,000				6,000
Asset retirement obligations			1,178				1,133
Other accrued liabilities			1,010				1,029
Total noncurrent liabilities			8,188				8,162
Commitments and contingencies:
Shareholders' equity:
Common stock, $0.01 par value; unlimited shares authorized 28,388,372 shares issued and 28,047,661
outstanding at March 31, 2015, 28,047,661 issued and outstanding at December 31, 2014			280				280
Additional paid-in capital			124,095				123,980
Accumulated deficit			(40,512	)			(16,809	)
Other comprehensive loss			(56	)			(56	)
Total shareholders' equity			83,807				107,395
Total liabilities and shareholders' equity		$	101,499			$	123,523

 

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except share and per share data)
		Three months ended March 31,
		2015				2014
Revenues:
Oil sales		$	2,297			$	7,574
Gas sales			331				481
NGL sales			51				201
Total revenues			2,679				8,256
Operating expenses:
Oil and gas			1,852				1,972
Oil and gas depreciation, depletion
and amortization			2,874				3,294
Impairment of oil and gas properties			19,240				--
Water treatment plant			458				457
Mineral holding costs			295				300
General and administrative			1,479				1,606
Total operating expenses			26,198				7,629
(Loss) income from operations			(23,519	)			627
Other income and (expenses):
Realized (loss) on risk
management activities			(114	)			(158	)
Unrealized (loss) on risk
management activities			(63	)			(173	)
Gain on the sale of assets			16				28
Miscellaneous income			39				21
Interest income			1				1
Interest expense			(63	)			(96	)
Total other income and (expenses)			(184	)			(377	)
(Loss) income before income taxes			(23,703	)			250

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except share and per share data)
		Three months ended March 31,
		2015				2014
Income taxes:
Current (provision for)			--				--
Deferred benefit from			--				--
			--				--
Net (loss) income		$	(23,703	)		$	250
(Loss) Earnings per share basic and diluted
(Loss) earnings		$	(0.85	)		$	0.01
		$	(0.85	)		$	0.01
Weighted average shares outstanding
Basic			28,047,661				27,738,083
Diluted			28,047,661				28,142,253

 

 

 

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (LOSS)
(Unaudited)
(In thousands)
		Three months ended March 31,
		2015				2014
Net (loss) income:		$	(23,703	)		$	250
Other comprehensive (loss):
Marketable securities, net of tax			--				(25	)
Total comprehensive (loss) income		$	(23,703	)		$	225

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
		For the three months ended March 31,
		2015				2014
Cash flows from operating activities:
Net (loss) income		$	(23,703	)		$	250
Adjustments to reconcile net (loss) income to
net cash provided by operations
Depreciation, depletion & amortization			2,941				3,362
Change in fair value of commodity price
risk management activities, net			63				173
Impairment of oil and gas properties			19,240				--
(Gain) on sale of assets			(16	)			(28	)
Noncash compensation			158				143
Noncash services			20				17
Accounts payable			567				270
Overpayment by operators			742				128
Net changes in assets and liabilities			1,809				54
Net cash provided by operating activities			1,821				4,369
Cash flows from investing activities:
Acquisition and development of oil and gas properties			(1,843	)			(8,495	)
Acquisition of property, plant and equipment			(4	)			(1,202	)
Proceeds from sale of property and equipment			16				28
Net change in restricted investments			(24	)			(16	)
Net cash (used in) investing activities:			(1,855	)			(9,685	)

 

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U.S. ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
		For the three months ended March 31,
		2015				2014
Cash flows from financing activities:
Issuance of common stock			--				(27	)
Proceeds from new debt			--				2,000
Net cash provided by financing activities			--				1,973
Net (decrease) in cash and cash equivalents			(34	)			(3,343	)
Cash and cash equivalents at beginning of period			4,010				5,855
Cash and cash equivalents at end of period		$	3,976			$	2,512
Supplemental disclosures:
Interest paid		$	63			$	96
Non-cash investing and financing activities:
Unrealized change from available for sale securities		$	--			$	25
Acquisition and development of oil and gas
properties through accounts payable		$	128			$	596
Acquisition and development of oil and gas properties
through asset retirement obligations		$	33			$	76

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The accompanying unaudited condensed consolidated financial statements for the periods ended March 31, 2015 and March 31, 2014 have been prepared by U.S. Energy Corp. ("we," "us," "U.S. Energy" or the "Company") in accordance with generally accepted accounting principles in the United States of America ("U.S. GAAP").  The financial statements at March 31, 2015 and December 31, 2014 include the Company's wholly owned subsidiary Energy One LLC ("Energy One"), which owns the majority of the Company's oil and gas assets.  The Condensed Consolidated Balance Sheet at December 31, 2014 was derived from audited financial statements.  In the opinion of the Company, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the financial position of the Company for the reported periods.  Entities in which the Company holds at least 20% ownership or in which there are other indicators of significant influence are accounted for under the equity method, whereby the Company records its proportionate share of the entities' results of operations.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted and certain prior period amounts have been reclassified to conform to the current period presentation.  The unaudited condensed consolidated financial statements should be read in conjunction with the Company's Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K").  Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q.

We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the "FASB."  The FASB determines GAAP, which we follow to ensure we consistently report our financial condition, results of operations, and cash flows.

For detailed descriptions of our significant accounting policies, please see the 2014 10-K (Note B, pages 87 to 96).

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant estimates include oil and gas reserves used for depletion and impairment considerations, accrued revenue and related receivables, valuation of commodity derivative instruments and the cost of future asset retirement obligations.  The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances.  Due to inherent uncertainties, including the future prices of oil and gas, these estimates could change in the near term and such changes could be material.

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Oil and Gas Properties

The Company follows the full cost method in accounting for its oil and gas properties.  Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center.  This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities.  Proceeds received from property disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.  The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves.  Excluded from amounts subject to depletion are costs associated with unproved properties.

Full Cost Pool - Full cost pool capitalized costs are amortized over the life of production of proven properties.  Capitalized costs at March 31, 2015 and December 31, 2014 which were not included in the amortized cost pool were $9.6 million and $12.5 million, respectively.  These costs consist of exploratory wells in progress, seismic costs that are being analyzed for potential drilling locations and land costs related to unevaluated properties.  No capitalized costs related to unevaluated properties are included in the amortization base at March 31, 2015 or December 31, 2014.

Ceiling Test Analysis - Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling.  The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions and financial derivatives that hedge our oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by (iv) the income tax effects related to differences between the book and tax basis of the crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

We perform a quarterly ceiling test for each of our oil and gas cost centers.  There is only one such cost center in 2015.  The reserves used in the ceiling test and the ceiling test itself incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value.  In arriving at the ceiling test for the quarter ended March 31, 2015, we used prices of $82.72 per barrel for oil and $3.882 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of our producing properties.  The discount factor used was 10%.

Primarily due to the lower oil prices, the Company recorded a proved property impairment of $19.2 million related to its oil and gas assets during the three months ended March 31, 2015.  Management will continue to review our unproved properties based on market conditions and other changes and, if appropriate, unproved property amounts may be reclassified to the amortized base of properties within the full cost pool.  Recent declines in the price of oil have significantly increased the risk of ceiling test write-downs in future periods.

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Wells in Progress - Wells in progress represent the costs associated with unproved wells that have not reached total depth or have not been completed as of period end.  They are classified as wells in progress and are withheld from the depletion calculation.  The costs for these wells are transferred to evaluated property when the wells reach total depth and are completed and the costs become subject to depletion and the ceiling test calculation in future periods.

Mineral Properties

We capitalize all costs incidental to the acquisition of mineral properties.  Mineral exploration costs are expensed as incurred.  When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred. All capitalized costs are charged to operations if we subsequently determine that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource. Mineral properties at March 31, 2015 and December 31, 2014 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.

Our carrying balance in the Mt. Emmons property at March 31, 2015 and December 31, 2014 is as follows:

		(In thousands)
		March 31,				December 31,
		2015				2014
Costs associated with Mount Emmons
beginning of year		$	21,942			$	20,739
Property purchase (1)			--				1,203
Costs at the end of the period		$	21,942			$	21,942

⁽¹⁾On January 21, 2014, the Company acquired Thompson Creek Metals' ("TCM") 50% interest in 160 acres of fee land in the vicinity of the Mt. Emmons project mining claims for $1.2 million.  The property was originally acquired jointly by the Company and TCM in January 2009.

Properties and Equipment

Components of Property, Plant and Equipment as of March 31, 2015 and December 31, 2014 are as follows:

		(In thousands)
		March 31,				December 31,
		2015				2014
Property, plant and equipment		$	8,320			$	8,346
Less accumulated depreciation			(4,441	)			(4,404	)
Net book value		$	3,879			$	3,942

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Land, buildings, improvements, machinery and equipment are carried at cost.  Depreciation of buildings, improvements, machinery and equipment is provided principally by the straight-line method over estimated useful lives ranging from 3 to 45 years.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk relating to its oil and gas production.  All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as cash flow hedges, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with forecasted future oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and classifies them as gain (loss) on derivative instruments, on a net basis, in our consolidated statements of operations. The Company may also use puts, calls and basis swaps from time to time.

The Company's Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the Chief Executive Officer or President. The agreements with approved counterparties identify the Chief Executive Officer and President as the only Company representatives authorized to execute trades. Please see Note 4, Commodity Price Risk Management, for further discussion.

Revenue Recognition

The Company records oil and natural gas revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled based on our interest in the properties. Natural gas balancing obligations as of March 31, 2015 were not significant.

Recent Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03").  The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset.  ASU 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied retrospectively.  Early adoption is permitted.  The adoption of this standard will not have an impact on the Company's consolidated financial statements, other than balance sheet reclassifications.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern ("ASU 2014-15").  The objective of ASU 2014-15 is to provide guidance on management's responsibility to evaluate whether there is substantial doubt about a company's ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter.  The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.

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In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers ("ASU 2014‑09").  The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.  ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016.  The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements.

There are no other new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of March 31, 2015.

We record the fair value of the reclamation liability for our inactive mining properties and our operating oil and gas properties as of the date that the liability is incurred.  We review the liability each quarter and determine if a change in estimate is required, and we accrete the discounted liability on a quarterly basis for the future liability.  Final determinations are made during the fourth quarter of each year.  We deduct any actual funds expended for reclamation during the quarter in which it occurs.

The following is a reconciliation of the total liability for asset retirement obligations:

		(In thousands)
		March 31,				December 31,
		2015				2014
Beginning asset retirement obligation		$	1,133			$	812
Accretion of discount			12				40
Liabilities incurred			33				310
Liabilities settled			--				(29	)
Ending asset retirement obligation		$	1,178			$	1,133
Mineral properties		$	192			$	187
Oil and Gas wells			986				946
Ending asset retirement obligation		$	1,178			$	1,133

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Through our wholly-owned subsidiary Energy One, we have entered into commodity derivative contracts ("economic hedges") with Wells Fargo, as described below.  The derivative contracts are priced using West Texas Intermediate ("WTI") quoted prices.  The Company is a guarantor of Energy One's obligations under the economic hedges.  The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of our future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and manage our exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements.  However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  The Company's derivative contracts are currently held with a single counterparty.  The Company has a netting arrangement with the counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination.  The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities.  Derivative instruments are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the settlement of derivatives are recorded in the realized (loss) gain on risk management activities line on the condensed consolidated statement of income.

Energy One's commodity derivative contracts as of March 31, 2015 are summarized below:

Quantity

Settlement Period

Counterparty

Basis

(Bbls/day)

Strike Price

Crude Oil Put

02/01/15 - 04/30/15

Wells Fargo

WTI

500

Put:

$

46.00

Crude Oil Costless Collar

05/01/15 - 12/31/15

Wells Fargo

WTI

500

Put:

$

45.00

Call:

$

58.79

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The following table details the fair value of the Company's derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the consolidated balance sheet (in thousands):

				As of March 31, 2015
				(In thousands)
Underlying Commodity		Location on Balance Sheet		Gross amounts of recognized assets and liabilities				Gross amounts offset in the condensed consolidated balance sheet				Net amounts of assets and liabilities presented in the condensed consolidated balance sheet
Crude oil derivative contract		Current assets		$	287			$	(287	)		$	--
Crude oil derivative contract		Current liabilities		$	350			$	(287	)		$	63

The following table summarizes the unrealized and realized gains and losses presented in the accompanying statements of operations:

		(In thousands)
		Three months ended March 31,
		2015				2014
Realized derivative (loss)		$	(114	)		$	(158	)
Unrealized derivative (loss)		$	(63	)		$	(173	)
Total realized and unrealized derivative (loss)		$	(177	)		$	(331	)

We follow authoritative guidance regarding fair value measurements for all assets and liabilities measured at fair value.  That guidance establishes a fair value hierarchy that prioritizes the inputs the Company uses to measure fair value based on the significance level of the following inputs:

·	Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

·	Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active and model-derived valuations whose inputs or significant value drivers are observable.

·	Level 3 - Significant inputs to the valuation model are unobservable.

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Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels.  We determine our estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, and quotes from third parties.

The following tables list the Company's assets and liabilities that are measured at fair value and their classification within the fair value hierarchy as of March 31, 2015 and December 31, 2014:

		(In thousands)
						Fair Value Measurements at March 31, 2015 Using
Description		March 31, 2015				(Level 1)				(Level 2)				(Level 3)
Available for sale securities		$	25			$	25			$	--			$	--
Total assets		$	25			$	25			$	--			$	--
Commodity risk management liability		$	63			$	--			$	63			$	--
Executive retirement program liability			1,245			$	--			$	--			$	1,245
Total liabilities		$	1,308			$	--			$	63			$	1,245
						Fair Value Measurements at December 31, 2014 Using
Description			December 31, 2014			(Level 1)				(Level 2)				(Level 3)
Available for sale securities		$	25			$	25			$	--			$	--
Total assets		$	25			$	25			$	--			$	--
Executive retirement program liability		$	1,309			$	--			$	--			$	1,309
Total liabilities		$	1,309			$	--			$	--			$	1,309

Fair Value of Available for Sale Securities

The fair value of available for sale securities is based on quoted market prices obtained from independent pricing services.  Accordingly, the Company has classified these instruments as Level 1.

Fair Value of Commodity Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of the counterparty and the Company's own credit rating.  In consideration of counterparty credit risk, the Company assessed the likelihood that the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.  At March 31, 2015 and December 31, 2014, derivative instruments utilized by the Company consist of "puts" and "no premium" collars.  The crude oil derivative markets are highly active.  Although the Company's derivative instruments are valued using indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

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Fair Value of Executive Retirement Program

The executive retirement program is a standalone liability for which there is no available market price, principal market, or market participants.  The Company records the estimated fair value of the long-term liability for estimated future payments under the executive retirement program based on the discounted value of estimated future payments associated with each individual in the program.  The inputs available for this estimate are unobservable and are therefore classified as Level 3 inputs.

Fair Value of Financial Instruments

Our other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt.  The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities.  The carrying value of our debt approximates its fair market value as it bears interest at variable rates over the term of the loan.  The fair value and carrying value of our debt was $6.0 million as of March 31, 2015.

Revolving Credit Facility

Energy One, a wholly-owned subsidiary the Company, has in place a credit facility with Wells Fargo Bank, National Association.  As of March 31, 2015, the maximum credit available under the credit facility was $100.0 million and the borrowing base under the facility was $24.5 million.  Effective April 15, 2015, the borrowing base under Energy One LLC's credit facility with Wells Fargo Bank, National Association was decreased from $24.5 million to $7.5 million.

As of March 31, 2015, the Company had $6.0 million in outstanding borrowings under the credit facility.  Borrowings under the credit facility are collateralized by Energy One's oil and gas producing properties.  Each borrowing under the agreement has a term of six months, but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility.  Our intent is to extend this debt and therefore we have classified it as a long-term liability.  The current weighted average interest rate on this debt is 2.68% at March 31, 2015.  As of March 31, 2015, Energy One was in compliance with all the covenants under the credit facility.

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Common Stock

The following table details the changes in common stock during the three months ended March 31, 2015:

(Amounts in thousands, except for share amounts)
										Additional
		Common Stock								Paid-In
		Shares				Amount				Capital
Balance January 1, 2015			28,047,661			$	280			$	123,980
Issuance of restricted stock			340,711				--				--
Stock-based compensation			--				--				115
Balance March 31, 2015			28,388,372			$	280			$	124,095

 

Restricted Stock

The Company grants shares of restricted stock as part of its equity compensation program. Shares of restricted stock are valued at the closing price of the Company's common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award.

During the three months ended March 31, 2015, the Company granted 340,711 shares of restricted stock under the 2012 Equity and Performance Incentive Plan (the "2012 Equity Plan") to certain employees.  The restricted shares vest in equal tranches over three years and had a fair value at issuance of $1.50 per share, which is equal to the closing price of the Company's stock on the date of grant.  Total expense recorded for restricted stock for the three months ended March 31, 2015 and 2014 was $41,000 and $0, respectively. As of March 31, 2015, there was $470,000 of total unrecognized compensation expense related to unvested restricted stock awards, which will be amortized through 2017.

A summary of the status and activity of non-vested restricted stock for the three-month period ended March 31, 2015 is presented in the following table:

		Restricted Shares				Weighted Average Grant-Date Fair Value
Non-vested at beginning of year			--			$	--
Granted			340,711			$	1.50
Non-vested at end of quarter			340,711			$	1.50

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Stock Option Plans

The following table represents the activity in employee stock options and non-employee director stock options for the three months ended March 31, 2015:

		Employee Stock Options								Director Stock Options
						Weighted								Weighted
						Average								Average
						Exercise								Exercise
		Options				Price				Options				Price
Outstanding balance at December 31, 2014			2,097,413			$	3.82				178,666			$	3.28
Granted			340,711			$	1.50				--			$	--
Forfeited			--			$	--				--			$	--
Expired			--			$	--				--			$	--
Exercised			--			$	--				--			$	--
Outstanding at March 31, 2015			2,438,124			$	3.50				178,666			$	3.28
Exercisable at March 31, 2015			1,949,080			$	3.95				97,333			$	3.23
Weighted Average Remaining Contractual Life - Years							4.26								7.64
Aggregate intrinsic value of options outstanding ($ Thousands)						$	--							$	--

Employee Stock Options.  During the three months ended March 31, 2015, we issued 340,711 options to certain employees under the 2012 Equity Plan.  The options were issued at the closing price of $1.50 on the date of grant, vest over a three year period and expire ten years from the date of grant.  These options were valued under the Black-Scholes pricing model using a risk free interest rate of 1.765%, expected life of six years and expected volatility of 63.3585%.  During the three months ended March 31, 2015 and 2014, we recorded $54,000 and $43,000, respectively, in compensation expense for employee stock options.  As of March 31, 2015, there was $369,000 of total unrecognized compensation cost related to employee stock options, which is expected to be amortized over a weighted average period of 2.33 years.

Director Stock Options.  During the three months ended March 31, 2015 and 2014, we recorded $20,000 and $16,000, respectively, in expense for options issued to non-employee directors.  As of March 31, 2015, there was $126,000 of total unrecognized compensation cost related to director stock options, which is expected to be amortized over a weighted average period of 2.30 years.

The Company uses the asset and liability method of accounting for deferred income taxes.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities.  Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

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The deferred income tax assets or liabilities for an oil and gas exploration company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices.  Accordingly, the asset or liability is subject to continual recalculation, and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

The Company does not expect to pay any federal or state income tax for 2015 as a result of net operating loss carry forwards from prior years.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is "more likely than not" that some component or all of the benefits of deferred tax assets will not be realized.  As of March 31, 2015, the Company maintains a full valuation allowance on its net deferred tax assets. Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.

As of March 31, 2015, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties.  A summary of results of operations for the three months ended March 31, 2015 and 2014, and total assets as of March 31, 2015 and December 31, 2014 by segment, are as follows:

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		(In thousands)
		For the three months ended March 31,
		2015				2014
Revenues:
Oil and gas		$	2,679			$	8,256
Total revenues			2,679				8,256
Operating expenses:
Oil and gas			23,966				5,266
Mineral properties			753				757
Total operating expenses			24,719				6,023
Interest expense:
Oil and gas			89				84
Mineral properties			--				--
Total interest expense			89				84
Operating income (loss)
Oil and gas		$	(21,376	)		$	2,906
Mineral properties			(753	)			(757	)
Operating income (loss)
from identified segments			(22,129	)			2,149
General and administrative expenses			(1,479	)			(1,606	)
Add back interest expense			89				84
Other revenues and expenses			(184	)			(377	)
Income (loss) before income taxes		$	(23,703	)		$	250
Depreciation depletion and amortization expense:
Oil and gas		$	2,874			$	3,294
Mineral properties			31				31
Corporate			36				37
Total depreciation depletion
amortization expense		$	2,941			$	3,362

 

 

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		(In thousands)
		March 31,				December 31,
		2015				2014
Assets by segment
Oil and gas		$	73,001			$	92,020
Mineral			21,945				21,942
Corporate			6,553				9,561
Total assets		$	101,499			$	123,523

Basic net income per common share is calculated by dividing net income available to common stockholders by the basic weighted-average common shares outstanding for the relevant period.  The Company's earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.  Diluted net income per common share is calculated by dividing adjusted net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options (which were assumed to have been exercised at the average market price of the common shares during the reporting period) and unvested restricted stock. The treasury stock method is used to measure the dilutive impact of unvested restricted stock and in-the-money stock options.

The following table sets forth the calculations of basic and diluted earnings per share (in thousands except share amounts and per share data):

		(In thousands except share amounts, and per share data)
		Three months ended March 31,
		2015				2014
Net income (loss)		$	(23,703	)		$	250
Basic weighted-average common shares outstanding			28,047,661				27,738,083
Add:  dilutive effect of stock options			--				404,170
Add:  dilutive effect of unvested restricted stock			--				--
Diluted weighted-average common shares outstanding			28,047,661				28,142,253
Basic net (loss) income per share		$	(0.85	)		$	0.01
Diluted net (loss) income per share		$	(0.85	)		$	0.01

The following options and unvested restricted stock, which could be potentially dilutive in future periods, were not included in the computation of diluted net loss per share because the effect would have been anti-dilutive for the periods indicated:

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		Three months ended March 31,
		2015		2014
Weighted-average anti-dilutive stock options		2,616,790		1,055,000
Weighted-average anti-dilutive restricted stock awards		336,925		--
		2,953,715		1,055,000

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.  Following are currently pending legal matters:

Water Rights Litigation –Mt. Emmons Project

On July 25, 2008, we filed an Application for Finding of Reasonable Diligence with the Colorado Water Court ("Water Diligence Application") concerning the conditional water rights associated with the Mt. Emmons Project (Case No. 2008CW81).  The conditional water decree ("Decree") required the Company to file its proposed plan of operations and associated permits with the Forest Service and BLM within six years of entry of the Decree, or within six years of the final determination of the pending patent application, whichever occurred later.  The BLM issued the mineral patents on April 2, 2004.  Although the issuance of the patents was appealed, on April 30, 2007, the United States Supreme Court made a final determination (by denial of certiorari) upholding BLM's issuance of the mineral patents.  The Company filed a plan of operations on March 31, 2010.  On April 20, 2015, the Colorado Water Court entered a decree granting the Water Diligence Application.  The decree continues the conditional water rights for a six-year period and requires the Company to submit a new Application for Finding of Reasonable Diligence in April 2021 if the water rights have not been applied to a beneficial use by that time.

Quiet Title Action – Dimmit County, TX

On October 4, 2013, Dimmit Wood Properties, Ltd. ("Dimmit") filed a quiet title, breach of contract, and trespass action against Chesapeake Exploration, LLC ("Chesapeake"), Crimson Exploration Operating, Inc. ("Crimson"), EXCO Operating Company, LP, OOGC America, Inc., Energy One and Liberty Energy, LLC ("Liberty") (jointly referred to as "Defendants") concerning an 800.77 gross acre oil and gas lease ("Lease") located in Dimmit County, Texas.  Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One has a 30% working interest.  Dimmit alleged that the Lease terminated due to the failure to achieve production in paying quantities and for having non-existent production for allegedly significant time periods.  On October 28, 2013, the Defendants filed an answer, asserting that production in paying quantities was achieved in the primary term of the Lease with an existing producing well and that the Lease has remained in good standing and had not terminated.  The Defendants also filed Counterclaims against Dimmit, including but not limited to breach of contract, as well as a third-party action against Sage Energy Company, alleging tortious interference with the lease.  On April 27, 2015, the Company, Crimson and Liberty agreed to settle

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the action.  According to the settlement, the Company will receive a cash payment in exchange for releasing its interest in the subject lease.  The settlement agreement does not affect a similar case involving Dr. Darrell Willerson, Sue Willerson and Willerson Energy Partners, L.P.

 

Effective April 15, 2015, the borrowing base under Energy One LLC's credit facility with Wells Fargo Bank, National Association was decreased from $24.5 million to $7.5 million.  The redetermination was based on reserves and production forecasts as of December 31, 2014, taking into account current oil and natural gas price forecasts.

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ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the three months ended March 31, 2015 and 2014.  The following also updates information as to our financial condition provided in our Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K").  Statements in the following discussion may be forward-looking and involve risk and uncertainty (see "Forward Looking Statements").  The following discussion should also be read in conjunction with our condensed consolidated financial statements and the notes thereto.

General Overview

We are an independent energy company focused on the acquisition and development of oil and gas producing properties in the continental United States.  Our business is currently focused in South Texas and the Williston Basin in North Dakota.  However, we do not intend to limit our focus to these geographic areas.  We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.

We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our operations to other geographic areas.  As a non-operator, we rely on our operating partners to propose, permit and manage wells.  Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis.  After the well is completed, our operating partners also transport, market and account for all production.  We are in the process of developing operational capabilities and expect to pursue opportunities to acquire operated properties and/or operatorship of existing properties.

We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons molybdenum project in Colorado.

Our current capitalized amounts in the oil and gas and mining areas at March 31, 2015 and December 31, 2014 were as follows:

		(In thousands)
		March 31,				December 31,
		2015				2014
Proved oil and gas properties		$	58,591			$	75,724
Unproved oil and gas properties			9,200				10,188
Exploratory wells in progress			368				2,357
Undeveloped mining properties			21,942				21,942
		$	90,101			$	110,211

Oil and Gas Activities

We have active agreements with several oil and gas exploration and production companies.  Our working interest varies by project (and may vary over time depending on the terms of the relevant agreement), but typically ranges from approximately 1% to 62%.  These projects may result in numerous wells being drilled over the next three to five years.  We are also actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies.  The following table details our interests in producing wells as of March 31, 2015 and 2014.

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	March 31,
	2015				2014
	Gross		Net(1)		Gross		Net(1)
Williston Basin:
Productive wells	102.00		10.32		97.00		10.62
Wells being drilled or awaiting completion	7.00		0.01		13.00		0.22
South Texas:
Productive wells	35.00		9.53		23.00		6.28
Wells being drilled or awaiting completion	2.00		0.46		2.00		0.60
Gulf Coast:
Productive wells	3.00		0.56		3.00		0.56
Wells being drilled or awaiting completion	--		--		--		--
Total:
Productive wells	140.00		20.41		123.00		17.46
Wells being drilled or awaiting completion	9.00		0.47		15.00		0.82

 

(1)	Net working interests may vary over time under the terms of the applicable contracts.

Our net investment in Williston Basin, North Dakota wells was $258,000 during the three months ended March 31, 2015.

Rough Rider Prospect.  We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Statoil Oil & Gas, L.P. ("Statoil").  From August 24, 2009 to March 31, 2015, we have drilled and completed 24 gross (6.39 net) Bakken formation wells and two gross (0.22 net) Three Forks formation wells under our Drilling Participation Agreement with Statoil.  Statoil operates all of the wells.

Yellowstone and SEHR Prospects.  We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC ("Zavanna").  Through March 31, 2015, we have drilled and completed 44 gross (3.11 net) Bakken formation wells and nine gross (0.33 net) Three Forks formation wells in these prospects.  The wells are operated by Zavanna (18 gross, 2.91 net), Emerald Oil, Inc. (30 gross, 0.35 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net).  During the first three months of 2015, we completed three gross (0.01 net) wells in the Yellowstone and SEHR prospects.

Bakken/Three Forks Asset Package.  In 2012, we acquired approximately 400 net acres in 23 drilling units in McKenzie, Williams and Mountrail Counties of North Dakota.  In June 2014, we sold our interest in eight of these 23 drilling units (approximately 285.7 net acres) for $12.2 million.   At March 31, 2015, there were 23 gross (0.24 net) producing wells in the remaining 15 drilling units.  At March 31, 2015, seven additional gross (0.01 net) wells had been spud and were in progress.

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Booth-Tortuga and Leona River Prospects.  We participate in the Booth-Tortuga and Leona River prospects with Contango Oil & Gas Company ("Contango").  At March 31, 2015, we have 30 gross (8.23 net) producing wells in these prospects, comprised of 16 gross (4.35 net) Buda limestone wells, three gross (0.90 net) Eagle Ford Shale wells and 11 gross (2.98 net) Austin Chalk wells.  One additional Buda limestone well (0.13 net) was in progress at March 31, 2015.  The wells are operated by Contango (28 gross, 8.08 net), WCS Oil & Gas Corporation (2 gross, 0.15 net) and CML Exploration (1 gross, 0.13 net).  Our net investment in these wells during the first three months of 2015, including lease acquisition and holding costs in the prospects, was $771,000.

Big Wells Prospect.   We participate in the Big Wells prospect with U.S. Enercorp.  At March 31, 2015, we have two gross (0.30 net) producing Buda limestone wells in this prospect.

Carrizo Creek and South McKnight Prospects.  We participate in the Carrizo Creek and South McKnight prospects with U.S. Enercorp.  At March 31, 2015, we have three gross (1.0 net) producing wells in these prospects.  One additional well (0.33 net) was in progress at March 31, 2015.  Our net investment in this acreage and wells during the three months ended March 31, 2015 was $941,000.

We participate with three different operators in the onshore U.S. Gulf Coast area.  At March 31, 2015, we had three gross (0.56 net) producing wells in this region.

The following table provides a regional summary of our net production during the first three months of 2015:

	Williston Basin		South Texas		Gulf Coast		Total
First Three Months of 2015 Production
Oil (Bbl)	45,880		13,323		4		59,207
Gas (Mcf)	25,354		44,932		42,545		112,831
NGLs (Bbl)	4,718		3,496		--		8,214
Equivalent (BOE)	54,824		24,308		7,095		86,227
Avg. Daily Equivalent (BOE/d)	609		270		79		958
Relative percentage	63.6%		28.2%		8.2%		100%

Uranium Properties

On August 14, 2014, conditioned upon the closing of a purchase and sale transaction between Anfield Resources Inc. ("Anfield") and Uranium One Inc. ("Uranium One"), the Company agreed to release Anfield from the future payment and royalty obligations stemming from the Company's 2007 sale of its uranium properties to Uranium One.  In return, Anfield has agreed to pay the Company the following:

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1.	$2.5 million in Anfield common shares upon closing of the transactions contemplated by the asset purchase agreement between Anfield and Uranium One.  The shares will be held in escrow and released in tranches over a 36 month period,

2.	$2.5 million in cash paid upon 18 months of continuous commercial production, and

3.	$2.5 million in cash paid upon 36 months of continuous commercial production.

As this transaction has not closed as of the date of this report, the timing of any potential future receipt of funds from any of these contingencies is not known.

Mount Emmons Molybdenum Project

With respect to the Mount Emmons project, the Company expects to continue its scoping analysis of the Mine Plan of Operations with the U.S. Forest Service through the balance of 2015.

Additional Comparative Data

The following table provides information regarding selected production and financial information for the quarter ended March 31, 2015 and the immediately preceding three quarters.

		For the Three Months Ended
		March 31, 2015				December 31,  2014				September 30, 2014				June 30, 2014
		(in thousands, except for production data)
Production (BOE)			86,227				101,265				142,484				116,499
Oil, gas and NGL production revenue		$	2,679			$	5,067			$	9,928			$	9,128
Unrealized and realized derivative gain (loss)		$	(177	)		$	829			$	696			$	(612	)
Impairment of oil and gas properties		$	19,240			$	--			$	--			$	--
Lease operating expense		$	1,594			$	2,585			$	2,238			$	1,807
Production taxes		$	258			$	467			$	790			$	779
DD&A		$	2,874			$	3,187			$	4,621			$	3,583
General and administrative		$	1,479			$	1,390			$	2,030			$	1,533
Mineral holding costs		$	295			$	166			$	439			$	205
Water treatment plant		$	458			$	475			$	491			$	452
Income (loss)		$	(23,703	)		$	(2,334	)		$	(63	)		$	56

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

During the three months ended March 31, 2015, we recorded a net loss after taxes of $23.7 million, or $0.85 per share basic and diluted, as compared to net income after taxes of $250,000, or $0.01 per share basic and diluted, during the same period of 2014.

Oil and Gas Operations.   Oil and gas operations generated an operating loss of $21.3 million during the quarter ended March 31, 2015 as compared to operating income of $3.0 million during the quarter ended March 31, 2014.  The following table summarizes production volumes, average sales prices and operating revenues for the three months ended March 31, 2015 and 2014:

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		Three Months Ended
		March 31,								Increase
		2015				2014				(Decrease)
Production volumes
Oil (Bbls)			59,207				83,565				(24,358	)
Natural gas (Mcf)			112,831				98,807				14,024
Natural gas liquids (Bbls)			8,215				5,060				3,155
Equivalent (BOE)			86,227				105,093				(18,866	)
Avg. Daily Equivalent (BOE/d)			958				1,168				(210	)
Average sales prices
Oil (per Bbl)		$	38.80			$	90.64			$	(51.84	)
Natural gas (per Mcf)			2.93				4.87				(1.94	)
Natural gas liquids (per Bbl)			6.21				39.72				(33.51	)
Equivalent (BOE)			31.07				78.56				(47.49	)
Operating revenues (in thousands)
Oil		$	2,297			$	7,574			$	(5,277	)
Natural gas			331				481				(150	)
Natural gas liquids			51				201				(150	)
Total operating revenue			2,679				8,256				(5,577	)
Oil and gas production expense			(1,594	)			(1,250	)			(344	)
Production taxes			(258	)			(722	)			464
Impairment			(19,240	)			--				(19,240	)
Income before depreciation, depletion and amortization			(18,413	)			6,284				(24,697	)
Depreciation, depletion and amortization			(2,874	)			(3,294	)			420
Income		$	(21,287	)		$	2,990			$	(24,277	)

During the three months ended March 31, 2015, we produced 86,227 BOE, or an average of 958 BOE/d as compared to 105,093 BOE or 1,168 BOE/d during the three months ended March 31, 2014.  In our South Texas region, production decreased 34%, from 36,725 BOE to 24,308 BOE as a result of normal production declines and fewer wells being drilled due to low commodity prices.  Production in our Bakken region decreased 11%, from 61,906 BOE to 54,824 BOE, as a result of normal production declines.  We expect these regional production trends to continue.  Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids ("NGLs") that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs is classified as oil and gas production expense.

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We recognized $2.7 million in revenues during the three months ended March 31, 2015 as compared to $8.3 million during the same period in 2014.  The $5.6 million decrease in revenue is primarily due to lower oil and gas prices and lower oil and gas sales volumes in the first quarter of 2015 as compared to the first quarter of 2014.

Our average net realized price (operating revenue per BOE) for the three months ended March 31, 2015 was $31.07 per BOE compared with $78.56 per BOE for the same period in 2014.  Due to takeaway constraints, the discount to West Texas Intermediate ("WTI") quoted prices, or differential, for oil prices in the Williston Basin has ranged from $15.00 to $16.50 per barrel during the three months ended March 31, 2015.  Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices from this region.

Oil and gas production expense of $1.6 million for the three months ended March 31, 2015 was comprised of $1.4 million in lease operating expense and $179,000 in workover expense.

During the three months ended March 31, 2015, the Company recorded a proved property impairment of $19.2 million related to its oil and gas assets.  The impairment was primarily due to the decline in the price of oil. There were no proved property impairments recorded during the first three months of 2014.

Our depletion, depreciation and amortization (DD&A) rate for the three months ended March 31, 2015 was $33.33 per BOE compared to $31.34 per BOE for the same period in 2014.  Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.

Mt. Emmons and Water Treatment Plant Operations.  We recorded $458,000 in costs and expenses for the water treatment plant and $295,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended March 31, 2015.  During the three months ended March 31, 2014, we recorded $457,000 in operating costs related to the water treatment plant and $300,000 in holding costs.

General and Administrative Expenses.  General and administrative expenses decreased by $127,000 during the three months ended March 31, 2015 compared to general and administrative expenses for the three months ended March 31, 2014.  The decrease in general and administrative costs in 2015 is primarily a result of a $102,000 reduction in professional services and a $25,000 reduction in other general and administrative costs.  The following table details the changes in the Company's general and administrative costs for the three months ended March 31, 2015 compared to the three months ended March 31, 2014:

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		(In thousands)
		For the three months ended March 31,
		2015				2014				Change
Professional services		$	172			$	274			$	(102	)
Director's fees			90				69				21
Contract services			94				106				(12	)
Executive retirement			15				23				(8	)
Other compensation			851				852				(1	)
Other costs			257				282				(25	)
Total general and administrative costs		$	1,479			$	1,606			$	(127	)

Other Income and Expenses.  We recognized an unrealized and realized derivative loss of $177,000 in the first quarter of 2015 compared to a loss of $331,000 for the same period in 2014.  The 2015 amount includes a gain on unrealized changes in the fair value of our commodity derivative contracts of $63,000 and realized cash settlement losses on derivatives of $114,000.

During the three months ended March 31, 2015, we recorded a $16,000 gain from the sale of assets.  During the three months ended March 31, 2014, we recorded a gain on the sale of assets of $28,000.

Interest income was $1,000 during each of the quarters ended March 31, 2015 and 2014.

As a result of lower average debt balances, interest expense decreased to $63,000 during the quarter ended March 31, 2015 from $96,000 during the quarter ended March 31, 2014.

Overview of Liquidity and Capital Resources

At March 31, 2015, we had $4.0 million in cash and cash equivalents and our working capital deficit (current assets minus current liabilities) was $3.9 million.  As discussed below in "Capital Resources and Capital Requirements", we project that our capital resources at March 31, 2015 will be sufficient to fund our operations and capital projects through the balance of 2015.  Given the size of our potential commitments related to our existing inventory of drilling projects, however, our requirements for capital could increase significantly over the next several months if, among other things, we make acquisitions or elect to participate in any currently unanticipated drilling of additional wells.  As a result, we may consider borrowing more than currently anticipated on our revolving credit facility, selling or joint venturing an interest in some of our oil and gas assets, or accessing the capital markets or other alternatives, as we determine how to best fund our capital program.

The principal recurring uncertainty which affects the Company is variable prices for oil and gas. Significant price swings can have adverse or positive effects on our business of exploring for, developing and producing oil and gas.  Availability of drilling and completion equipment and crews fluctuates with the market prices for oil and natural gas and thereby affects the cost of drilling and completing wells.  When prices are low there is typically less exploration activity and the cost of drilling and completing wells is generally reduced.  Conversely, when prices are high there is generally more exploration activity and the cost of drilling and completing wells generally increases.

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Capital Resources

Primary potential sources of future liquidity include the following:

Oil and Gas Production.  At March 31, 2015, we had 140 gross (20.41 net) producing wells.  During the three months ended March 31, 2015, we received an average of $893,000 per month from these producing wells with an average operating cost of $531,000 per month (including workover costs) and production taxes of $86,000, for average net cash flows of $276,000 per month from oil and gas production before non-cash depletion expense.  We anticipate that cash flows from oil and gas operations through the balance of 2015 will approximate average cash flows for the first three months of 2015.  However, decreases in the price of oil and natural gas, increased operating costs and workover expenses, declines in production rates, and other factors could reduce these average monthly cash flow amounts.

Normal production declines and the back-in after payout provisions granted to certain of our counterparties will eventually decrease the amount of cash flow we receive from the relevant wells.  We anticipate drilling more wells with current partners and with others in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.

Cash on Hand.  At March 31, 2015, we had $4.0 million in cash and cash equivalents.

Wells Fargo Revolving Credit Facility.  On July 30, 2010, we established a senior credit facility through our wholly owned subsidiary Energy One to borrow up to $75 million (since increased to $100 million as described below) from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association, which acquired the North American reserve-based and related diversified energy lending business of our initial lending institution, BNP Paribas.  The senior credit facility is being used to advance our short and mid-term goals of increasing our investment in oil and gas.  As of the date of this report, the commitment amount is $100 million and the borrowing base is $7.5 million.

From time to time until the expiration of the credit facility (July 30, 2017), if Energy One is in compliance with the facility documents, Energy One may borrow, pay, and re-borrow funds from the lenders, up to an amount equal to the borrowing base.  The borrowing base is redetermined semi-annually, taking into account updated reserve reports.  Any proposed increase in the borrowing base will require approval by all lenders in the syndicate, and any proposed borrowing base decrease will require approval by lenders holding not less than two-thirds of outstanding loans and loan commitments.

Energy One is required to comply with customary affirmative covenants and with certain negative covenants.  The principal negative financial covenants (measured at various times as provided in the Credit Agreement) do not permit (i) the Interest Coverage Ratio (Interest Expense to EBITDAX) to be less than 3.0 to 1; (ii) Total Debt to EBITDAX to be greater than 3.5 to 1; and (iii) the Current Ratio (current assets plus unused lender commitments under the Borrowing Base) to be less than 1.0 to 1.0.  EBITDAX is defined in the Credit Agreement as Consolidated Net Income, plus non-cash charges.

If Energy One fails to pay interest or principal when due, or fails to comply with the covenants in the Credit Agreement (after a reasonable cure period, if applicable), Wells Fargo as Administrative Agent may (and shall, if requested by the Majority Lenders (Lenders holding not less than 2/3rds of the outstanding loan principal), declare the loans immediately due, and foreclose on Energy One's assets and enforce USE's guaranty.

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As of March 31, 2015, Energy One was in compliance with all the covenants under the revolving credit facility, however, reduction of the borrowing base, effective April 15, 2015, from $24.5 million to $7.5 million will make compliance with the Current Ratio covenant more difficult, and potentially unachievable, beginning as of June 30, 2015.  Further, if oil prices continue to remain depressed through the end of 2015, we may not be able to borrow additional funds under the revolver due to limitations under the Total Debt to EBITDAX covenant.  Additionally, Energy One is restricted from transferring funds to the Company if the amount borrowed under the senior credit facility exceeds 80% of the borrowing base, or if a Borrowing Base Deficiency, Default or Event of Default exists or would exist after such payment.  In the short term, we believe that the Company has sufficient funds to meet its obligations, but in the longer term, this restriction could cause cash shortfalls for the Company.

As of the date of this report, we have outstanding borrowings of $6.0 million under the credit facility.

Capital Requirements

Our direct capital requirements during the balance of 2015 relate to the funding of our drilling programs, the potential acquisition of prospective oil and gas properties and/or existing production, payment of debt obligations, operating and capital improvement costs relating to the water treatment plant at Mt. Emmons, ongoing permitting activities for the Mt. Emmons project and general and administrative costs.  We intend to finance our 2015 capital expenditure plan primarily from the sources described above under "Capital Resources".  We may be required to reduce or defer part of our 2015 capital expenditures plan if we are unable to obtain sufficient financing from these sources.  We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements and other factors.

Oil and Gas Exploration and Development.  Through March 31, 2015, we have spent approximately $2.0 million of our $8.2 million 2015 oil and gas capital expenditure budget.  The remaining $6.2 million is currently budgeted to be spent on exploration and acquisition initiatives in South Texas and in the Williston Basin of North Dakota.  Actual capital expenditures for each regional drilling program are contingent upon timing, well costs and success.  If any of our drilling initiatives are not initially successful or progress more slowly than anticipated, funds allocated for that program may be allocated to other initiatives and/or acquisitions in due course.  The actual number of gross and net wells could vary in each of these cases.

Mt. Emmons Molybdenum Project.  We are responsible for all costs associated with the Mt. Emmons project, which includes operation of a water treatment plant.  Operating costs for the water treatment plant during the remainder of 2015 are expected to be approximately $144,000 per month and holding costs related to the mine are expected to average $90,000 per month.

Insurance.  We have liability insurance coverage in amounts we deem sufficient and in line with industry standards for the location, stage of development, and type of assets we operate.  Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in diminished operations.  We have property loss insurance on all major assets equal to the approximate replacement value of the assets.

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Reclamation Costs.  We have reclamation obligations with an estimated present value of $986,000 related to our oil and gas wells and $191,000 related to the Mt. Emmons molybdenum property.  No reclamation is expected to be performed in 2015 unless a well, or wells, are abandoned due to unexpected operational challenges or if a well becomes uneconomical.  As the Mt. Emmons project is developed, the reclamation liability is expected to increase.  Our objective, upon closure of the proposed mine at the Mt. Emmons project, is to eliminate long-term liabilities associated with the property.

Cash Flows During the Three Months Ended March 31, 2015

The following table presents changes in cash flows between the three month periods ended March 31, 2015 and 2014.  The analysis following the table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.

		(In thousands)
		For the three months ended March 31,
		2015				2014				Change
Net cash provided by operating activities		$	1,821			$	4,369			$	(2,548	)
Net cash (used in) investing activities			(1,855	)			(9,685	)			7,830
Net cash provided by financing activities			--				1,973				(1,973	)

Operating Activities.  Cash provided by operations for the three month period ended March 31, 2015 decreased to $1.8 million as compared to cash provided by operations of $4.4 million for the same period of 2014.  This $2.6 million year over year decrease in cash from operating activities is primarily due to lower oil and gas revenue, partially offset by lower oil and gas operating expenses during the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.  For further discussion related to cash provided by operations, please refer to "Results of Operations" above.

Investing Activities.  During the three months ended March 31, 2015, investing activities consumed cash through the acquisition and development of oil and gas properties in the amount of $1.8 million, the acquisition of equipment in the amount of $4,000 and a net change of $24,000 in restricted investments.  During this period, investing activities provided $16,000 in cash from the sale of used equipment.

The $7.8 million change in investing activities during the three months ended March 31, 2015 as compared to the same period of 2014 is primarily a result of: (a) a $6.7 million decrease in expenditures for acquisitions and development of oil and gas, (b) $1.2 million decrease in acquisitions of  properties and equipment, (c) $16,000 in proceeds from the sale of property and equipment in 2015 as compared to $28,000 during the 2014 period, and (d) an $8,000 decrease in the balance of restricted investments.

Financing Activities.  There were no financing activities during the three months ended March 31, 2015.  During the three months ended March 31, 2014, financing activities provided $2.0 million through additional borrowings under our credit facility.

For detailed descriptions of our critical accounting policies and estimates, we refer you to the corresponding section of Part II, Item 7 of our 2014 10-K (please see pages 69 to 72).

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Future Operations

Management intends to continue the development of our oil and gas portfolio as well as seek additional investment opportunities in the oil and natural gas sector.  Long term, we intend to fund the holding and permitting costs associated with the Mt. Emmons property.

Effects of Changes in Prices

Natural resource operations are significantly affected by changes in commodity prices.  As prices for a particular commodity increase, values for prospects for that commodity typically also increase, making acquisitions of such properties more costly and sales potentially more valuable.  Conversely, a price decline could present acquisition opportunities related to that commodity, but could also make sales of such properties more difficult.  Operational impacts of changes in commodity prices are common in the oil and gas and mining industries.

At March 31, 2015, we are receiving revenues from our oil and gas business.  Our revenues, cash flows, future rate of growth, results of operations, financial condition and ability to finance projected acquisitions of oil and gas producing assets are dependent upon prevailing prices for oil and gas.

Forward Looking Statements

This Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act").  All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements.  When used in this Form 10-Q, the words "will", "expect", "anticipate", "intend", "plan", "believe", "seek", "estimate" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words.  Forward-looking statements in this Form 10-Q include statements regarding our expected future revenue, income, production, liquidity, cash flows, reclamation and other liabilities, expenses and capital projects, future capital expenditures and future transactions.  Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements due to a variety of factors, including those associated with our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil, NGL and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals businesses.  In particular, careful consideration should be given to cautionary statements made in the "Risk Factors" section of our 2014 10-K and other quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference.  The Company undertakes no duty to update or revise any forward-looking statements.

Forward-looking statements also include those relating to the permitting and approval process for the Mount Emmons molybdenum project (the "Project").  There can be no assurance that U.S. Energy will receive the permits and approvals necessary to pursue the Project.  In addition, such permits and approvals, if received, could be unreasonably or unexpectedly delayed or made subject to conditions that reduce the benefits of the Project or render it uneconomic.  The process under NEPA may be longer than

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the Company expects, may involve substantial costs, and may require substantial management attention.  The mine, if constructed, could be substantially different in scope, productivity and economic potential than the mine contemplated in the Mine Plan of Operations.  In addition, if constructed, the operation of the mine will be subject to a wide variety of operating, commodity-price related and financial risks.

None

We had three principal categories of contractual obligations at March 31, 2015:  Debt to third parties of $6.0 million, executive retirement obligations of $1.2 million and asset retirement obligations of $1.1 million.

The debt to third parties consists of $6.0 million in debt under our revolving credit facility.  Each borrowing under the revolving credit facility has a term of six months but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility.  The executive retirement liability will be paid out over varying periods starting after the actual retirement dates of the covered executives.  The asset retirement obligations are expected to be retired during the next 31 years.

ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas.  The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, and this volatility will impact our revenues.

To mitigate some of our commodity risk, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and gas production.  We may also use puts, calls and basis swaps from time to time.   We do not hold or issue derivative instruments for trading purposes.  The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of our future oil production, to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements.  However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions.

Through Energy One, we have entered into commodity derivative contracts ("economic hedges") with Wells Fargo as described below.  The derivative contracts are priced using West Texas Intermediate ("WTI") quoted prices.  The Company is a guarantor of Energy One's obligations under the economic hedges.

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Energy One's commodity derivative contracts as of March 31, 2015 are summarized below:

Quantity

Settlement Period

Counterparty

Basis

(Bbls/day)

Strike Price

Crude Oil Put

02/01/15 - 04/30/15

Wells Fargo

WTI

500

Put:

$

46.00

Crude Oil Costless Collar

05/01/15 - 12/31/15

Wells Fargo

WTI

500

Put:

$

45.00

Call:

$

58.79

These contracts are accounted for using the mark-to-market accounting method and accordingly, we recognize all unrealized and realized gains and losses related to these contracts currently in earnings and such gains and losses are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations.  For further details regarding our derivative contracts, please refer to Note 4, Commodity Price Risk Management under Part I, Item 1 of this report.

ITEM 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of March 31, 2015, the Company's management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act).  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:

i.

That the Company's disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and (b) that such information is accumulated and communicated to the Company's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure; and

ii.	That the Company's disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.  Legal Proceedings

Water Rights Litigation –Mt. Emmons Project

On July 25, 2008, we filed an Application for Finding of Reasonable Diligence with the Colorado Water Court ("Water Diligence Application") concerning the conditional water rights associated with the Mt. Emmons Project (Case No. 2008CW81).  The conditional water decree ("Decree") required the Company to file its proposed plan of operations and associated permits with the Forest Service and BLM within six years of entry of the Decree, or within six years of the final determination of the pending patent application, whichever occurred later.  The BLM issued the mineral patents on April 2, 2004.  Although the issuance of the patents was appealed, on April 30, 2007, the United States Supreme Court made a final determination (by denial of certiorari) upholding BLM's issuance of the mineral patents.  The Company filed a plan of operations on March 31, 2010.  On April 20, 2015, the Colorado Water Court entered a decree granting the Water Diligence Application.  The decree continues the conditional water rights for a six-year period and requires the Company to submit a new Application for Finding of Reasonable Diligence in April 2021 if the water rights have not been applied to a beneficial use by that time.

Quiet Title Action – Dimmit County, TX

On October 4, 2013, Dimmit Wood Properties, Ltd. ("Dimmit") filed a quiet title, breach of contract, and trespass action against Chesapeake Exploration, LLC ("Chesapeake"), Crimson Exploration Operating, Inc. ("Crimson"), EXCO Operating Company, LP, OOGC America, Inc., Energy One and Liberty Energy, LLC ("Liberty") (jointly referred to as "Defendants") concerning an 800.77 gross acre oil and gas lease ("Lease") located in Dimmit County, Texas.  Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One has a 30% working interest.  Dimmit alleged that the Lease terminated due to the failure to achieve production in paying quantities and for having non-existent production for allegedly significant time periods.  On October 28, 2013, the Defendants filed an answer, asserting that production in paying quantities was achieved in the primary term of the Lease with an existing producing well and that the Lease has remained in good standing and had not terminated.  The Defendants also filed Counterclaims against Dimmit, including but not limited to breach of contract, as well as a third-party action against Sage Energy Company, alleging tortious interference with the lease.  On April 27, 2015, the Company, Crimson and Liberty agreed to settle the action.  According to the settlement, the Company will receive a cash payment in exchange for releasing its interest in the subject lease.  The settlement agreement does not affect a similar case involving Dr. Darrell Willerson, Sue Willerson and Willerson Energy Partners, L.P.

There have been no other material changes from the legal proceedings as previously disclosed in our 2014 10-K in response to Item 3 of Part I of such Form 10-K (pages 47-48).

ITEM 1A. Risk Factors

There have been no material changes to the risk factors discussed in Part I, "Item 1A - Risk Factors" (pages 13 to 30) in the 2014 10-K which may materially affect the Company's business, financial condition or future results.  Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may materially adversely affect its business, financial condition and/or operating results.

ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None

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ITEM 3.  Defaults Upon Senior Securities

Not Applicable

ITEM 4.  Mine Safety Disclosures

None

ITEM 5.  Other Information

Not Applicable

ITEM 6.  Exhibits

	31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
	101.INS	XBRL Instance Document
	101.SCH	XBRL Schema Document
	101.CAL	XBRL Calculation Linkbase Document
	101.LAB	XBRL Label Linkbase Document
	101.PRE	XBRL Presentation Linkbase Document
	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document