US ENERGY CORP
10-Ks and 10-Qs
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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x
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Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
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For the quarter ended June 30, 2010 or
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o
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Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
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For the transition period from ___________ to ____________
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Commission File Number: 0-6814
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U.S. ENERGY CORP.
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(Exact name of registrant as specified in its charter)
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Wyoming
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83-0205516
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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877 North 8
th
West, Riverton, WY
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82501
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(Address of principal executive offices)
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(Zip Code)
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Registrant's telephone number, including area code:
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(307) 856-9271
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Not Applicable
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(Former name, address and fiscal year, if changed since last report)
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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.
YES
x
NO
o
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 Regulations 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).
YES
o
NO
o
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
o
Accelerated filer
o
Non-accelerated filer
x
(Do not check if a smaller reporting company)Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES
o
NO
x
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
At August 6, 2010, there were issued and outstanding 26,856,290 shares of the Company’s common stock, $.01 par value.
-2-
U.S. ENERGY CORP. and SUBSIDIARIES
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Page No.
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PART I.
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FINANCIAL INFORMATION
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Item 1.
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Financial Statements.
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Condensed
Balance Sheets as of June 30, 2010 (unaudited) and December 31, 2009 (unaudited)
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4-5
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Condensed
Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009 (unaudited)
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6
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Condensed
Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009 (unaudited)
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7-8
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Notes
to Condensed Financial Statements (unaudited)
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9-23
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Item 2.
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Management’s
Discussion and Analysis of Financial Condition and Results of Operations
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24-40
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Item 3.
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Quantitative
and Qualitative Disclosures About Market Risk
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40
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Item 4.
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Controls
and Procedures
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40
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PART II.
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OTHER INFORMATION
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Item 1.
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Legal
Proceedings
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41-43
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Item 1A.
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Risk
Factors
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43
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Item 2.
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Unregistered
Sales of Equity Securities and Use of Proceeds
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43
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Item 3.
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Defaults
Upon Senior Securities
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43
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Item 4.
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Submission
of Matters to a Vote of Security Holders
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43
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Item 5.
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Other
Information
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43
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Item 6.
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Exhibits
and Reports on Form 8-K
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44
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45
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Certifications
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See Exhibits
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-3-
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U.S. ENERGY CORP.
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(Unaudited)
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(In thousands)
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June 30,
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December 31,
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|||||||
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2010
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2009
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CURRENT ASSETS:
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Cash and cash equivalents
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$ | 6,112 | $ | 33,403 | ||||
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Marketable securities
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||||||||
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Held to maturity - treasuries
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34,426 | 22,059 | ||||||
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Available for sale securities
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873 | 1,178 | ||||||
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Accounts receivable
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Trade
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3,022 | 3,882 | ||||||
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Reimbursable project costs
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33 | 2 | ||||||
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Income taxes
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353 | 353 | ||||||
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Other current assets
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1,068 | 1,223 | ||||||
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Total current assets
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45,887 | 62,100 | ||||||
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INVESTMENT
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2,962 | 2,958 | ||||||
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PROPERTIES AND EQUIPMENT:
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Oil & gas properties under full cost method, net
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40,035 | 26,002 | ||||||
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Undeveloped mining claims
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22,001 | 21,969 | ||||||
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Commercial real estate, net
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22,749 | 23,200 | ||||||
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Property, plant and equipment, net
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9,445 | 9,301 | ||||||
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Net properties and equipment
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94,230 | 80,472 | ||||||
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OTHER ASSETS
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1,214 | 1,193 | ||||||
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Total assets
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$ | 144,293 | $ | 146,723 | ||||
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U.S. ENERGY CORP.
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CONDENSED BALANCE SHEETS
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LIABILITIES AND SHAREHOLDERS' EQUITY
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(Unaudited)
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(In thousands, except shares)
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June 30,
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December 31,
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|||||||
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2010
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2009
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CURRENT LIABILITIES:
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Accounts payable
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$ | 1,242 | $ | 6,500 | ||||
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Accrued compensation
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1,150 | 1,748 | ||||||
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Current portion of long-term debt
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200 | 200 | ||||||
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Other current liabilities
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232 | 224 | ||||||
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Total current liabilities
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2,824 | 8,672 | ||||||
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LONG-TERM DEBT, net of current portion
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600 | 600 | ||||||
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DEFERRED TAX LIABILITY
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8,179 | 7,345 | ||||||
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ASSET RETIREMENT OBLIGATIONS
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234 | 211 | ||||||
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OTHER ACCRUED LIABILITIES
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831 | 762 | ||||||
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SHAREHOLDERS' EQUITY:
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Common stock, $.01 par value; unlimited shares
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||||||||
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authorized; 26,834,706 and 26,418,713
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shares issued, respectively
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268 | 264 | ||||||
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Additional paid-in capital
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120,279 | 118,998 | ||||||
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Accumulated surplus
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10,882 | 9,485 | ||||||
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Unrealized gain on marketable securities
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196 | 386 | ||||||
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Total shareholders' equity
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131,625 | 129,133 | ||||||
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Total liabilities and shareholders' equity
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$ | 144,293 | $ | 146,723 | ||||
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U.S. ENERGY CORP.
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(Unaudited)
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(In thousands except per share data)
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||||||||||||||||
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Three months ended June 30,
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Six months ended June 30,
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|||||||||||||||
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2010
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2009
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2010
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2009
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OPERATING REVENUES:
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Oil and gas
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$ | 6,218 | $ | 754 | $ | 13,927 | $ | 1,428 | ||||||||
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Real estate
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608 | 745 | 1,247 | 1,479 | ||||||||||||
| 6,826 | 1,499 | 15,174 | 2,907 | |||||||||||||
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OPERATING COSTS AND EXPENSES:
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Oil and gas
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3,894 | 787 | 7,279 | 1,599 | ||||||||||||
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Impairment of oil and gas properties
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-- | -- | -- | 1,063 | ||||||||||||
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Real estate
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602 | 498 | 1,155 | 1,010 | ||||||||||||
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Water treatment plant
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459 | 576 | 808 | 1,019 | ||||||||||||
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Mineral holding costs
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(5 | ) | -- | 52 | -- | |||||||||||
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General and administrative
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2,167 | 1,832 | 4,835 | 3,837 | ||||||||||||
| 7,117 | 3,693 | 14,129 | 8,528 | |||||||||||||
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OPERATING INCOME (LOSS)
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(291 | ) | (2,194 | ) | 1,045 | (5,621 | ) | |||||||||
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OTHER INCOME AND (EXPENSES):
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Gain on sale of assets
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-- | -- | 115 | 5 | ||||||||||||
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Equity gain/(loss) in
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unconsolidated investment
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179 | (75 | ) | 1,142 | (166 | ) | ||||||||||
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Gain on sale of marketable securities
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8 | -- | 8 | -- | ||||||||||||
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Miscellaneous income and (expenses)
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(20 | ) | 49 | 1 | 44 | |||||||||||
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Interest income
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22 | 44 | 61 | 141 | ||||||||||||
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Interest expense
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(18 | ) | (20 | ) | (35 | ) | (58 | ) | ||||||||
| 171 | (2 | ) | 1,292 | (34 | ) | |||||||||||
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INCOME (LOSS) BEFORE
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||||||||||||||||
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FOR INCOME TAXES
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(120 | ) | (2,196 | ) | 2,337 | (5,655 | ) | |||||||||
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INCOME TAXES:
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Current (provision for) benefit from
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-- | (467 | ) | -- | 210 | |||||||||||
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Deferred (provision for) benefit from
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(10 | ) | (222 | ) | (940 | ) | 213 | |||||||||
| (10 | ) | (689 | ) | (940 | ) | 423 | ||||||||||
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INCOME (LOSS) FROM
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CONTINUING OPERATIONS
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(130 | ) | (2,885 | ) | 1,397 | (5,232 | ) | |||||||||
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NET INCOME (LOSS)
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$ | (130 | ) | $ | (2,885 | ) | $ | 1,397 | $ | (5,232 | ) | |||||
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NET INCOME (LOSS) PER SHARE
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Basic
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$ | -- | $ | (0.13 | ) | $ | 0.05 | $ | (0.24 | ) | ||||||
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Diluted
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$ | -- | $ | (0.13 | ) | $ | 0.05 | $ | (0.24 | ) | ||||||
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Weighted average shares outstanding
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Basic
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26,734,636 | 21,311,266 | 26,611,583 | 21,481,944 | ||||||||||||
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Diluted
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26,734,636 | 21,311,266 | 27,813,215 | 21,481,944 | ||||||||||||
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U.S. ENERGY CORP.
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(Unaudited)
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(In thousands)
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Six months ended June 30,
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||||||||
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2010
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2009
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CASH FLOWS FROM OPERATING ACTIVITIES:
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Net income (loss)
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$ | 1,397 | $ | (5,232 | ) | |||
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Adjustments to reconcile net income (loss) to net cash
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provided by (used in) operations
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Depreciation, depletion and amortization
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5,408 | 2,070 | ||||||
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Accretion of discount on treasury investment
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(34 | ) | (94 | ) | ||||
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Impairment of oil and gas properties
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-- | 1,063 | ||||||
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Gain on sale of marketable securities
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(8 | ) | -- | |||||
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Equity (gain)/loss from Standard Steam
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(1,142 | ) | 166 | |||||
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Deferred income taxes
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944 | (213 | ) | |||||
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Gain on sale of assets
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(115 | ) | (5 | ) | ||||
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Noncash compensation
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752 | 837 | ||||||
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Noncash services
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30 | 35 | ||||||
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Net changes in assets and liabilities
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291 | (600 | ) | |||||
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NET CASH PROVIDED BY
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(USED IN) OPERATING ACTIVITIES
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7,523 | (1,973 | ) | |||||
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CASH FLOWS FROM INVESTING ACTIVITIES:
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Acquisition and development of oil and gas properties
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$ | (23,734 | ) | $ | (1,283 | ) | ||
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Net (investment in) redemption of treasury investments
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(12,332 | ) | 10,369 | |||||
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Distribution from Standard Steam
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1,138 | -- | ||||||
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Acquisition and development of mining properties
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(32 | ) | (10 | ) | ||||
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Mining property option payment
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-- | 1,000 | ||||||
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Development of real estate
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-- | (90 | ) | |||||
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Acquisition of property and equipment
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(466 | ) | (168 | ) | ||||
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Proceeds from sale of property and equipment
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118 | 5 | ||||||
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Proceeds from sale of marketable securities
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13 | -- | ||||||
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Net change in restricted investments
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(22 | ) | 4,782 | |||||
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NET CASH (USED IN) PROVIDED
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BY INVESTING ACTIVITIES
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(35,317 | ) | 14,605 | |||||
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U.S. ENERGY CORP.
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CONDENSED STATEMENTS OF CASH FLOWS
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(Unaudited)
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(In thousands)
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Six months ended June 30,
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2010
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2009
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CASH FLOWS FROM FINANCING ACTIVITIES:
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Issuance of common stock
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$ | 503 | $ | -- | ||||
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Repayments of debt
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-- | (17,688 | ) | |||||
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Stock buyback program
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-- | (1,399 | ) | |||||
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NET CASH PROVIDED BY (USED IN)
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FINANCING ACTIVITIES
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503 | (19,087 | ) | |||||
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NET DECREASE IN
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CASH AND CASH EQUIVALENTS
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(27,291 | ) | (6,455 | ) | ||||
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CASH AND CASH EQUIVALENTS
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AT BEGINNING OF PERIOD
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33,403 | 8,434 | ||||||
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CASH AND CASH EQUIVALENTS
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AT END OF PERIOD
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$ | 6,112 | $ | 1,979 | ||||
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SUPPLEMENTAL DISCLOSURES:
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Income tax (received)
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$ | -- | $ | (144 | ) | |||
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Interest paid
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$ | 11 | $ | 29 | ||||
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NON-CASH INVESTING AND FINANCING ACTIVITIES:
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Unrealized gain
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$ | 196 | $ | 143 | ||||
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Acquisition and development of oil and gas
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properties through accounts payable
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$ | 458 | $ | -- | ||||
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Acquisition and development of oil and gas
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through asset retirement obligation
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$ | 14 | $ | -- | ||||
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Development of mining properties
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through asset retirement obligation
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$ | -- | $ | -- | ||||
-8-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
1)
Basis of Presentation
The accompanying unaudited condensed financial statements for the periods ended June 30, 2010 and June 30, 2009 have been prepared by U.S. Energy Corp. (“USE” or the “Company”) in accordance with generally accepted accounting principles (“GAAP”) in the United States of America. The Condensed Balance Sheet at December 31, 2009 was derived from audited financial statements. In the opinion of the Company, the accompanying condensed 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 generally accounted for by 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 GAAP have been condensed or omitted. The unaudited condensed financial statements should be read in conjunction with the Company's December 31, 2009 Annual Report on Form 10-K. Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q. See Note 11.
2) Summary of Significant Accounting Policies
For detailed descriptions of the Company’s significant accounting policies, please see Form 10-K for the year ended December 31, 2009 (Note B pages 84 to 92).
We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow to ensure we consistently report our financial condition, results of operations, and cash flows.
The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of the
FASB Accounting Standards Codification,
™
sometimes referred to as the Codification or ASC. The Codification does not change how the Company accounts for its transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, the Company refers to topics in the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America 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 and the cost of future asset retirement obligations. 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.
Index
-9-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
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.
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, financial derivatives that hedge the Company’s 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, less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil 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. At June 30, 2010, the book value of the Company’s oil and gas properties did not exceed the cost center ceiling.
Revenue Recognition
The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Natural gas balancing obligations as of June 30, 2010 were not significant.
Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.
Recent Accounting Pronouncements
As of June 30, 2010, there have been no recent accounting pronouncements currently relevant to the Company in addition to those discussed on pages 90 to 92 of our Annual Report on Form 10-K for the year ended December 31, 2009. The Company continues to review current outstanding statements from the FASB and does not believe that any of those statements will have a material effect on the financial statements of the Company when adopted.
Index
-10-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
3) Properties and Equipment
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.
Components of Property and Equipment as of June 30, 2010 and December 31, 2009 are as follows:
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(In thousands)
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June 30,
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December 31,
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|||||||
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2010
|
2009
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|||||||
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Oil & Gas properties
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||||||||
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Unproved
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$ | 4,456 | $ | 3,993 | ||||
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Well in progress
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8,753 | 1,367 | ||||||
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Proved
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35,431 | 24,595 | ||||||
| 48,640 | 29,955 | |||||||
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Less accumulated depreciation
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||||||||
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depletion and amortization
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(8,605 | ) | (3,953 | ) | ||||
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Net book value
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40,035 | 26,002 | ||||||
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Mining properties
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22,001 | 21,969 | ||||||
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Commercial real estate
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24,622 | 24,600 | ||||||
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Less Accumulated depreciation
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(1,873 | ) | (1,400 | ) | ||||
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Net book value
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22,749 | 23,200 | ||||||
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Building, land and equipment
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14,386 | 14,196 | ||||||
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Less accumulated depreciation
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(4,941 | ) | (4,895 | ) | ||||
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Net book value
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9,445 | 9,301 | ||||||
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Totals
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$ | 94,230 | $ | 80,472 | ||||
Oil and Gas Exploration Activities
The Company participates in oil and gas projects as a non-operating working interest owner and has active agreements with several oil and gas exploration and production companies. Our working interest varies by project, but typically ranges from approximately 5% to 65%. These projects may result in numerous wells being drilled over the next three to five years.
Index
-11-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
Williston Basin, North Dakota
During the first six months of 2010, the Company completed 3 gross wells (1.02 net) with net costs to the Company of $5.3 million. Two additional gross wells (0.86 net) were drilled and awaiting completion at June 30, 2010 with net costs to the Company of $6.0 million. This brings the total wells drilled through June 30, 2010 under the Drilling Participation Agreement with Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership, wholly-owned by Brigham Exploration Company (a Delaware corporation), to 9 gross completed and producing wells (3.99 net) and two gross wells (0.86 net) in progress. The remaining 4 gross initial wells under the Drilling Participation Agreement will be drilled during the balance of 2010.
As a result of participating in all 15 wells, the Company will earn the rights to drill an additional 15 wells in the Bakken formation and potentially an additional 30 wells in the Three Forks formation for a total of 60 wells if the state of North Dakota allows two wells per formation in each spacing unit. Brigham operates all of the wells. If the spacing is ultimately increased to three wells per 1,280 acre spacing unit, the potential number of drilling locations could increase to 90. The drilling of each well typically takes 30 days while the completion typically takes 21-28 days.
U.S. Gulf Coast
In February 2010, the Company spud a well (0.042 net), the ALMI #1, targeting a gas prospect located in south central Louisiana. In the second quarter of 2010, the well was deemed to be nonproductive and has been plugged and abandoned. The Company’s net investment in this well was $396,000 through June 30, 2010.
In February 2010, the Company spud a well (0.10 net), the Main Pass 74 #A-19, targeting an oil and gas prospect located 15 miles offshore of south east Louisiana. In the second quarter of 2010, the well was deemed to be nonproductive and has been plugged and abandoned. The Company’s net investment in this well was $3.1 million through June 30, 2010.
In March 2010, the Company drilled a productive well (0.048 net), the Weyerhaeuser 18 #1, targeting a gas prospect in Louisiana. During the second quarter of 2010, the operator experienced water related issues with this well. The well is currently shut-in and under evaluation. The net capitalized cost to the Company through June 30, 2010 is $88,000.
In May 2010, the Company spud a well (0.048 net), the Weyerhaeuser 57 #2, targeting an oil prospect in Louisiana. The well encountered its target zone and completion activities were in progress at June 30, 2010. The Company’s investment in this well through June 30, 2010 was $210,000.
In June 2010, the Company spud a well (0.50 net), the ALMI #8, targeting a gas prospect in south central Louisiana. Drilling was in progress at June 30, 2010, with net costs to the Company of $2.4 million.
The Company is also actively pursuing the potential of acquiring additional exploration, development or production stage oil and gas properties or companies. To further this effort, the Company has engaged an investment banker to assist in finding, evaluating and if necessary, financing the potential acquisition of such assets.
Index
-12-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at June 30, 2010 and December 31, 2009 which were not included in the amortized cost pool were $13.2 and $5.4 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations and land costs, all related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at June 30, 2010 and December 31, 2009. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.
Ceiling Test Analysis
– The Company performs a quarterly ceiling test for each of its oil and gas cost centers, which in 2010, there was only one. The ceiling test incorporates 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 June 30, 2010, the Company used $75.76 per barrel for oil and $4.10 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 the Company’s producing properties. The discount factor used was 10%.
At June 30, 2010, the ceiling was in excess of the net capitalized costs as adjusted for related deferred income taxes and no impairment was required. The Company had a reserve report completed for its Bakken wells for the period ended June 30, 2010. The reserve report indicated an addition of approximately 510,000 BOE in reserves from wells completed in 2010 and improvement in oil prices used for the ceiling test calculation from $61.18 to $75.76 per barrel. Furthermore, as of June 30, 2010, there were no unproved properties that were considered to be impaired and reclassified to properties being amortized. Management will continue to review its 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. During the six months ended June 30, 2009, the Company recorded a $1.1 million impairment.
Wells in Progress -
Wells in progress represent the costs associated with wells that have not reached total depth or have not been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.
Mineral Properties
The Company capitalizes 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 the Company subsequently determines 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 June 30, 2010 and December 31, 2009 reflect capitalized costs associated with the Company’s Mount Emmons molybdenum property near Crested Butte, Colorado. The Company has entered into an agreement with Thompson Creek Metals Company USA (“TCM”) to develop this property. TCM may earn up to a 75% interest in the project for the investment of $400 million.
Index
-13-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
The Company’s carrying balance in the Mount Emmons property at June 30, 2010 and December 31, 2009 is as follows:
|
(In thousands)
|
||||
|
Costs associated with Mount Emmons
|
||||
|
at December 31, 2009
|
$ | 21,969 | ||
|
Development costs during the six months
|
||||
|
ended June 30, 2010
|
32 | |||
| $ | 22,001 | |||
Real Estate
The Company evaluates its long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are generally based on market appraisals. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on the Company's financial position and results of operations. The Company does not obtain appraisals on an ongoing basis for the property. The Company however did obtain an appraisal in 2009. Rental property conditions have not changed significantly in the area of the Company’s property. At June 30, 2010 and December 31, 2009, management determined that no impairment existed on the Company’s long-lived asset as the 2009 appraised value exceeded construction and carrying value, rental rates remained strong and costs remain within projected limits.
4) Asset Retirement Obligations
The Company accounts for its asset retirement obligations under FASB ASC 410-20, "
Asset Retirement Obligations
." The Company records the fair value of the reclamation liability on its inactive mining properties and its operating oil and gas properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required as well as accretes the discounted liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. The Company deducts 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)
|
||||||||
|
June 30,
|
December 31,
|
|||||||
|
2010
|
2009
|
|||||||
|
Beginning asset retirement obligation
|
$ | 211 | $ | 144 | ||||
|
Accretion of discount
|
8 | 12 | ||||||
|
Liabilities incurred
|
15 | 55 | ||||||
|
Ending asset retirement obligation
|
$ | 234 | $ | 211 | ||||
|
Mining properties
|
$ | 134 | $ | 128 | ||||
|
Oil & Gas Wells
|
100 | 83 | ||||||
|
Ending asset retirement obligation
|
$ | 234 | $ | 211 | ||||
Index
-14-
5) Fair Value
The Company adopted Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) on January 1, 2008, as it relates to financial assets and liabilities. The Company adopted FASB ASC 820 on January 1, 2009, as it relates to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs the Company to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:
|
·
|
Level 1 — Unadjusted quoted prices is available in active markets for identical assets or liabilities.
|
|
·
|
Level 2 — Pricing inputs, other than quoted prices within Level 1, which are either directly or indirectly observable.
|
|
·
|
Level 3 — Pricing inputs that are unobservable requiring the Company to use valuation methodologies that result in management’s best estimate of fair value.
|
The Company’s 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. The fair value of the Company’s other accrued liabilities are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair values of the other accrued liabilities that are reflected on the balance sheet are detailed below.
|
(In thousands)
|
||||||||||||||||
|
Fair Value Measurements at June 30, 2010 Using
|
||||||||||||||||
|
June 30,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
|
Description
|
2010
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Other accrued liabilities
|
$ | 831 | -- | -- | $ | 831 | ||||||||||
|
Total
|
$ | 831 | $ | -- | $ | -- | $ | 831 | ||||||||
|
Fair Value Measurements at December 31, 2009 Using
|
||||||||||||||||
|
December 31,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
|
Description
|
2009 |
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Other accrued liabilities
|
$ | 762 | -- | -- | $ | 762 | ||||||||||
|
Total
|
$ | 762 | $ | -- | $ | -- | $ | 762 | ||||||||
Index
-15-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
The other accrued liabilities are the long term portion of the Company’s executive retirement program.
As of June 30, 2010, the Company held $35.3 million of investments in government securities and marketable securities. The fair value of the investments is reflected on the balance sheet as detailed below.
|
(In thousands)
|
||||||||||||||||
|
Fair Value Measurements at June 30, 2010 Using
|
||||||||||||||||
|
June 30,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
|
Description
|
2010
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Held to maturity - treasuries
|
$ | 34,426 | $ | 34,426 | $ | -- | $ | -- | ||||||||
|
Available for sale securities
|
873 | 873 | -- | -- | ||||||||||||
|
Total
|
$ | 35,299 | $ | 35,299 | $ | -- | $ | -- | ||||||||
|
Fair Value Measurements at December 31, 2009 Using
|
||||||||||||||||
|
December 31,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
|
Description
|
2009 |
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Held to maturity - treasuries
|
$ | 22,059 | $ | 22,059 | $ | -- | $ | -- | ||||||||
|
Available for sale securities
|
1,178 | 1,178 | -- | -- | ||||||||||||
|
Total
|
$ | 23,237 | $ | 23,237 | $ | -- | $ | -- | ||||||||
Index
-16-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
The following table summarizes, by major security type, the fair value and any unrealized gain of the Company’s investments. The unrealized gain is recorded on the consolidated balance sheet as other comprehensive income, a component of shareholders’ equity.
|
(In thousands)
|
||||||||||||||||||||||||
|
June 30, 2010
|
||||||||||||||||||||||||
|
Less Than 12 Months
|
12 Months or Greater
|
Total
|
||||||||||||||||||||||
|
Unrealized
|
Unrealized
|
Unrealized
|
||||||||||||||||||||||
|
Description of Securities
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
||||||||||||||||||
|
Held to maturity - treasuries
|
$ | 34,426 | $ | -- | $ | -- | $ | -- | $ | 34,426 | $ | -- | ||||||||||||
|
Available for sale securities
|
873 | 206 | -- | -- | 873 | 206 | ||||||||||||||||||
|
Total
|
$ | 35,299 | $ | 206 | $ | -- | $ | -- | $ | 35,299 | $ | 206 | ||||||||||||
|
December 31, 2009
|
||||||||||||||||||||||||
|
Less Than 12 Months
|
12 Months or Greater
|
Total
|
||||||||||||||||||||||
|
Unrealized
|
Unrealized
|
Unrealized
|
||||||||||||||||||||||
|
Description of Securities
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
Fair Value
|
Gain
|
||||||||||||||||||
|
Held to maturity - treasuries
|
$ | 22,059 | $ | -- | $ | -- | $ | -- | $ | 22,059 | $ | -- | ||||||||||||
|
Available for sale securities
|
1,178 | 602 | -- | -- | 1,178 | 602 | ||||||||||||||||||
|
Total
|
$ | 23,237 | $ | 602 | $ | -- | $ | -- | $ | 23,237 | $ | 602 | ||||||||||||
The Company’s 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 the Company’s long-term debt approximates its fair market value since interest rates have remained generally unchanged from the issuance of the long-term debt. The following is the estimated fair value and carrying value of our other financial instruments at each of these dates:
|
(In thousands)
|
||||||||||||||||
|
June 30, 2010
|
December 31, 2009
|
|||||||||||||||
|
Description
|
Carry Amount
|
Fair Value
|
Carry Amount
|
Fair Value
|
||||||||||||
|
Long-term debt
|
$ | 800 | $ | 800 | $ | 800 | $ | 800 | ||||||||
Index
-17-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
At June 30, 2010, long term debt consists of debt related to the purchase of land which bears an interest rate of 6% per annum. The debt is due in four equal annual payments of $200,000, plus accrued interest, beginning on January 2, 2011.
7) Shareholders’ Equity
Common Stock
During the three and six months ended June 30, 2010, the Company issued 332,048 and 415,993 shares of common stock, respectively. These shares consist of (a) 40,000 shares issued to officers of the Company pursuant to the 2001 Stock Compensation Plan; (b) 236,367 shares issued as a result of warrants being exercised and (c) 139,626 shares as a result of the exercise of options by employees of the Company.
The following table details the changes in common stock during the six months ended June 30, 2010:
|
(Amounts in thousands, except for share amounts)
|
||||||||||||
|
Additional
|
||||||||||||
|
Common Stock
|
Paid-In
|
|||||||||||
|
Shares
|
Amount
|
Capital
|
||||||||||
|
Balance December 31, 2009
|
26,418,713 | $ | 264 | $ | 118,998 | |||||||
|
2001 stock compensation plan
|
40,000 | -- | 245 | |||||||||
|
Exercise of employee stock options
|
139,626 | 1 | (201 | ) | ||||||||
|
Exercise of stock warrants
|
236,367 | 3 | 700 | |||||||||
|
Expense of employee options vesting
|
-- | -- | 507 | |||||||||
|
Stock options issued to outside directors
|
-- | -- | 28 | |||||||||
|
Expense of company warrants issued
|
-- | -- | 2 | |||||||||
|
Balance June 30, 2010
|
26,834,706 | $ | 268 | $ | 120,279 | |||||||
Stock Option Plans
The Board of Directors adopted, and the shareholders approved, the U.S. Energy Corp. 2001 Incentive Stock Option Plan (the "2001 ISOP") for the benefit of USE's employees. The 2001 ISOP reserves for issuance shares of the Company’s common stock equal to 25% of the Company’s shares of common stock issued and outstanding at any time. The 2001 ISOP has a term of 10 years.
During the three and six months ended June 30, 2010, the Company recognized $254,000 and $507,000, respectively, in compensation expense related to employee options. The Company will recognize an additional $1.5 million in expense over the remaining vesting life of the outstanding options of 1.5 years. The Company computes the fair values of its options granted using the Black-Scholes pricing model.
Index
-18-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
Warrants to Others
From time to time the Company issues stock purchase warrants to non-employees for services. During the six months ended June 30, 2010, the Company issued 10,000 warrants to an independent director. The warrants were issued at the closing price of $5.04 on the date of grant, vest over a three year period and expire ten years from the date of grant. The options were valued under Black-Scholes using a risk free interest rate of 2.235%, expected life of 6 years and expected volatility of 63.79%.
During the three and six months ended June 30, 2010, the Company recorded $15,000 and $30,000, respectively, in expense for warrants issued to third parties. The Company will recognize an additional $105,000 in expense over the vesting period of the outstanding warrants. 139,626 shares were issued as a result of the exercise of 357,650 options held by officers and employees during the six months ended June 30, 2010.
The following table represents the activity in employee stock options and non-employee stock purchase warrants for the six months ended June 30, 2010:
|
June 30, 2010
|
||||||||||||||||
|
Employee Stock Options
|
Stock Purchase Warrants
|
|||||||||||||||
|
Weighted
|
Weighted
|
|||||||||||||||
|
Average
|
Average
|
|||||||||||||||
|
Exercise
|
Exercise
|
|||||||||||||||
|
Options
|
Price
|
Warrants
|
Price
|
|||||||||||||
|
Outstanding balance at December 31, 2009
|
3,711,114 | $ | 3.64 | 581,367 | $ | 2.91 | ||||||||||
|
Granted
|
- | $ | - | 10,000 | $ | 5.04 | ||||||||||
|
Forfeited
|
- | $ | - | (20,000 | ) | $ | 2.52 | |||||||||
|
Expired
|
- | $ | - | - | $ | - | ||||||||||
|
Exercised
|
(357,650 | ) | $ | 2.84 | (236,367 | ) | $ | 2.97 | ||||||||
|
Outstanding at June 30, 2010
|
3,353,464 | $ | 3.72 | 335,000 | $ | 2.95 | ||||||||||
|
Exercisable at June 30, 2010
|
2,558,469 | $ | 3.69 | 258,334 | $ | 2.98 | ||||||||||
|
Weighted Average Remaining Contractual Life - Years
|
5.38 | 4.54 | ||||||||||||||
|
Aggregate intrinsic value of options / warrants outstanding
|
$ | 3,731,000 | $ | 607,000 | ||||||||||||
8) Income Taxes
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 basis 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.
Index
-19-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
The total future deferred income tax liability is complicated for any energy company to estimate due in part to the long-lived nature of depleting oil and gas reserves and variables such as product prices. Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.
The Internal Revenue Service has audited the Company’s and subsidiaries tax returns through the year ended May 31, 2000. The Company’s income tax liabilities are settled through fiscal 2000.
9) Segment Information
As of June 30, 2010, the Company had three reportable segments: Oil and Gas, Real Estate Operations, and Maintenance of Mineral Properties.
A summary of results of operations for the three and six months ended June 30, 2010, and 2009, and total assets as of June 30, 2010 and December 31, 2009 by segment are as follows:
Index
-20-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
|
(Unaudited)
|
||||||||||||||||
|
(In thousands)
|
||||||||||||||||
|
For the three months
|
For the six months
|
|||||||||||||||
|
ended June 30,
|
ended June 30,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil and gas
|
$ | 6,218 | $ | 645 | $ | 13,927 | $ | 1,428 | ||||||||
|
Real estate
|
608 | 745 | 1,247 | 1,479 | ||||||||||||
|
Total revenues:
|
6,826 | 1,390 | 15,174 | 2,907 | ||||||||||||
|
Operating expenses:
|
||||||||||||||||
|
Oil and gas
|
$ | 3,894 | $ | 678 | $ | 7,279 | $ | 1,599 | ||||||||
|
Impairment of oil and gas properties
|
-- | -- | -- | 1,063 | ||||||||||||
|
Real estate
|
602 | 498 | 1,155 | 1,010 | ||||||||||||
|
Mineral properties
|
454 | 576 | 860 | 1,019 | ||||||||||||
|
Total operating expenses:
|
4,950 | 1,752 | 9,294 | 4,691 | ||||||||||||
|
Interest expense
|
||||||||||||||||
|
Oil and gas
|
$ | -- | $ | -- | $ | -- | $ | -- | ||||||||
|
Real estate
|
-- | -- | -- | 19 | ||||||||||||
|
Mineral properties
|
12 | 30 | 24 | 30 | ||||||||||||
|
Total interest expense:
|
12 | 30 | 24 | 49 | ||||||||||||
|
Operating income/(loss)
|
||||||||||||||||
|
Oil and gas
|
$ | 2,324 | $ | (33 | ) | $ | 6,648 | $ | (1,234 | ) | ||||||
|
Real estate
|
6 | 247 | 92 | 450 | ||||||||||||
|
Mineral properties
|
(466 | ) | (606 | ) | (884 | ) | (1,049 | ) | ||||||||
|
Operating income/(loss)
|
1,864 | (392 | ) | 5,856 | (1,833 | ) | ||||||||||
|
Other revenues and expenses:
|
(1,984 | ) | (1,804 | ) | (3,519 | ) | (3,822 | ) | ||||||||
|
Income/(loss) before
|
||||||||||||||||
|
income taxes
|
$ | (120 | ) | $ | (2,196 | ) | $ | 2,337 | $ | (5,655 | ) | |||||
|
Depreciation expense:
|
||||||||||||||||
|
Oil and gas
|
$ | 2,396 | $ | 261 | $ | 4,651 | $ | 1,320 | ||||||||
|
Real estate
|
266 | 607 | 531 | 521 | ||||||||||||
|
Mineral properties
|
18 | 13 | 36 | 28 | ||||||||||||
|
Corporate
|
94 | 100 | 190 | 201 | ||||||||||||
|
Total depreciation expense
|
2,774 | 981 | 5,408 | 2,070 | ||||||||||||
Index
-21-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
|
(In thousands)
|
||||||||
|
June 30,
|
December 31,
|
|||||||
|
2010
|
2009
|
|||||||
|
Assets by segment
|
||||||||
|
Oil and Gas properties
|
$ | 43,022 | $ | 30,016 | ||||
|
Real estate
|
23,002 | 23,450 | ||||||
|
Mineral properties
|
22,056 | 21,998 | ||||||
|
Corporate assets
|
56,213 | 71,259 | ||||||
|
Total assets
|
$ | 144,293 | $ | 146,723 | ||||
10) Equity Income in Unconsolidated Investment
The Company recorded an equity gain from its unconsolidated investment in Standard Steam, LLC. (“SST”) during the six months ended June 30, 2010 of $1.1 million and during the quarter ended June 30, 2010 of $179,000. These gains came as a result of the sale of two of the geothermal properties owned by SST and the negotiation of discounts on previously recorded accounts payable.
11) Subsequent Events
Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q.
BNP reserve lending facility
On July 30, 2010, U.S. Energy Corp. ("
USE"
) established a Senior Secured Revolving Credit Facility (the “
Facility
”) to borrow up to $75 million from BNP Paribas (“
BNPP
”). At present, BNPP is the only lender under the Facility. In the future, the facility may include other members of a lending syndicate (the “
Lenders
”) as provided for in the Facility. BNPP also is the administrative agent for the Facility, which is governed by the following documents: Credit Agreement; Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement (the “
Mortgage
”); and Guaranty and Pledge Agreement (the “
Guaranty
”), which are referred to below together as the “
Facility Documents
.” The following summarizes the principal provisions of the Facility as set forth in the Facility Documents, which are filed as exhibits to this Report. The summary is qualified by reference to the complete text of the documents.
USE has organized a wholly-owned subsidiary, Energy One LLC (“
Energy One
”), which will be the borrower under the Facility. USE has assigned to Energy One all of its rights, title and interest in certain oil and gas properties and equipment related thereto, rights under various operating agreements, proceeds from sale of production and from sale or other disposition of the properties. USE also has unconditionally and irrevocably guaranteed Energy One’s performance of its obligations under the Credit Agreement, including without limitation Energy One’s payment of all borrowings and related fees thereunder.
Index
-22-
U.S. ENERGY CORP.
Notes to Condensed Financial Statements (Unaudited)
(Continued)
From time to time until expiration of the Facility (July 30, 2014), 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, which has been initially established at $12 million. As of the date of this Report, Energy One has not borrowed from the Facility.
The Borrowing Base will be redetermined semi-annually, taking into account updated reserve reports prepared by USE’s independent consulting engineers. Any proposed increase in the Borrowing Base will require approval by all Lenders in the syndicate (presently only BNPP), and any proposed Borrowing Base decrease will require approval by Lenders holding not less than two-thirds of outstanding loans and loan commitments.
Interest will be payable quarterly at the greater of the Prime Rate, the Federal Funds Effective Rate (plus 0.5%), and the adjusted LIBO for the three prior months, plus, an additional 2.25% to 3.25%, depending on the amount of the loan relative to the Borrowing Base. Interest rates on outstanding loans are adjustable each day by BNPP as administrative agent. Energy One may prepay principal at any time without premium or penalty, but all outstanding principal will be due on July 30, 2014. If there is a decrease in the Borrowing Base, the excess of outstanding loans over the Borrowing Base will be due over the six months following the redetermination.
In addition, on a quarterly basis, Energy One will pay BNPP, for the account of each Lender (as applicable), a commitment fee of 0.50% of the unused amount of each Lender’s unused amount of its Facility lending commitment, computed daily until July 30, 2014.
Energy One is required to comply with customary affirmative covenants, and with negative covenants. The principal negative financial covenants (measured at various times as provided in the Credit Agreement) do not permit (i) 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) 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), BNPP as Administrative Agent may (and shall, if requested by the Majority Lenders (Lenders holding not less than 2/3 of the outstanding loan principal), declare the loans immediately due, and foreclose on Energy One’s assets and enforce USE’s guaranty.
At closing, pursuant to a separate fee letter with BNPP, USE paid BNPP $145,000 for initial arrangement and upfront fees, $59,320 to BNPP’s legal counsel for legal fees, and will be paying BNPP a commercially reasonable Facility fees in the future if the Borrowing Base is increased. Additionally, USE has paid Madison Williams and Company, investment banker to USE, $240,000 under the terms of a 2009 financial services agreement, in proportion to the initial $12 million Borrowing Base.
Index
-23-
The following is Management's Discussion and Analysis of significant factors that have affected the Company's liquidity, capital resources and results of operations during the three and six months ended June 30, 2010 and 2009. The following also updates information as to our financial condition provided in our 2009 Annual Report on Form 10-K. Statements in the following discussion maybe forward-looking and involve risk and uncertainty. The following discussion should also be read in conjunction with our condensed financial statements and notes thereto.
General Overview
The Company is involved in the exploration for and development of oil and gas, minerals and geothermal energy as well as real estate operations. The Company’s primary objective in the short to mid-term is to develop and acquire oil and gas producing properties as well as advance its geothermal properties through development, joint venture or sale. The long-term goal of the Company is to participate in the development of the Mount Emmons molybdenum property in Colorado. The Company also owns a multifamily housing complex as well as other real estate property which provide cash flows to fund operations. The Company’s primary goal is to improve shareholder value by developing long-term recurring revenues, cash flows and net income.
FASB Codification Discussion
We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (GAAP) that we follow to ensure we consistently report our financial condition, results of operations, and cash flows.
The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of the
FASB Accounting Standards Codification,
™
sometimes referred to as the Codification or ASC. The Codification does not change how the Company accounts for its transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, the Company refers to topics in the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.
Liquidity and Capital Resources
At June 30, 2010, the Company had $6.1 million in cash and cash equivalents and $34.4 million in U.S. Treasuries with longer than 90-day maturities from date of purchase for a total of $40.5 million or $1.51 per outstanding common share. The Company’s working capital (current assets minus current liabilities) was $43.1 million. As discussed below in Capital Resources and Capital Requirements, the Company projects that its capital resources at June 30, 2010 will be sufficient to fund its operations and capital projects through the balance of 2010.
On July 30, 2010, the Company established a Senior Secured Revolving Credit Facility (the “
Facility
”) to borrow up to $75 million from a syndicate of banks, financial institutions and other entities, including BNP Paribas (“
BNPP
”). The Company formed a wholly owned subsidiary, Energy One LLC (“Energy One”), to own all of its oil and gas properties as well as the Credit Facility. The Company through Energy One may borrow, pay, and re-borrow funds under the Facility, up to an amount equal to the Borrowing Base, which has been initially established at $12 million. See Note 11 to the financial statements. Additionally, the Company has in place a line of credit with a commercial bank in the amount of $10.0 million.
Index
-24-
The principal recurring trend which affects the Company is variable prices for commodities producible from our mineral properties, although the extent and grade of discovered minerals can mitigate or aggravate the impact of price swings. As commodities experience lower values in the market place, it is typically less expensive to acquire properties and hold them until prices raise to levels which either allow the properties to be sold or placed into production through joint venture partners, or by the Company for its own account. Availability of exploration drilling equipment and crews fluctuates with the market prices for oil and natural gas. When prices are low there is typically less exploration activity and the cost of drilling is typically reduced. Conversely, when prices are high there is typically more exploration activity and the cost of drilling typically increases.
Cash flows during the six months ended June 30, 2010
:
|
·
|
Operations provided $7.5 million, Investing Activities consumed $35.3 million and Financing Activities provided $503,000 for a net decrease in cash of $27.3 million during the six months ended June 30, 2010. During the six months ended June 30, 2009, Operations consumed $2.0 million, Investing Activities provided $14.6 million and Financing activities consumed $19.1 million for a net decrease of $6.5 million.
|
|
·
|
For a discussion on cash provided by Operations please refer to Results of Operations below.
|
Investing Activities
:
|
·
|
Investing activities consumed cash through the acquisition and development of oil and gas properties, $23.7 million, investment in treasury investments, $12.3 million, acquisition of property and equipment, $466,000, development of mineral claims, $32,000, and $22,000 in restricted investments
|
|
·
|
Cash was provided by investing activities as a result of the Company’s receipt of a capital distribution from Standard Steam Trust, LLC, (“SST”), $1.1 million, sale of a commercial office property, $118,000, and sale of marketable securities, $13,000.
|
Financing Activities
:
|
·
|
The Company received $503,000 for the issuance of shares related to the exercise of employee options and warrants to third party consultants.
|
Following is a discussion regarding the Company’s Capital Resources and Capital Requirements during the balance of 2010. For longer-range projections of the Company’s capital resources and requirements, please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.
Capital Resources
Sources of capital during the balance of 2010 are expected to consist of (1) the sale of oil and gas production from the Company’s existing and anticipated oil and gas operations, (2) cash on hand, (3) receipts of cash for the rental of real estate properties, (4) long-term financing of the Company’s multifamily housing complex, and (5) a line of credit in the amount of $10.0 million.
Index
-25-
Oil and Gas Production
At June 30, 2010, the Company had thirteen producing wells. During the six months ended June 30, 2010, the Company received on average $2.3 million per month from these producing wells with average operating cost of $145,000 per month, production taxes of $293,000 before non cash depletion expense, for average cash flows of $1.9 million per month from oil and gas production. The Company anticipates that cash flows from oil and gas operations will increase through the balance of 2010 as the remaining wells being drilled with Brigham Oil & Gas, L.P. (“Brigham”) a Delaware limited partnership wholly-owned by Brigham Exploration Company (a Delaware corporation), begin to produce. Decreases in the price of oil and natural gas and declines in production rates however could decrease these monthly cash flow amounts.
The decline of production from the existing Bakken wells and the back-in provision granted Brigham after pay back of drilling costs will decrease the amount of cash flow the Company receives from the oil production in the existing Bakken wells. The Company anticipates drilling more Bakken and TF wells with Brigham and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.
The Company had a reserve report completed for its Bakken wells for the period ended June 30, 2010. The reserve report indicated an addition of approximately 510,000 BOE in reserves from wells completed in 2010 and improvement in oil prices used for the ceiling test calculation from $61.18 to $75.76 per barrel.
The ultimate amount of cash that will be derived from the production of oil and gas will be determined by the price of oil and gas, the amount of production and production costs. The ultimate life of producing wells will likewise be impacted by market prices and costs of production. The Company plans on continuing in the oil and gas exploration business and may also acquire existing oil and gas properties.
Cash on Hand
At June 30, 2010, the Company had $6.1 million in cash and cash equivalents and $34.4 million in U.S. Treasuries. The Company has invested its cash in interest bearing accounts, with the majority invested in U.S. Government Treasuries. During the past two years, this investment policy has insured the preservation of principal and yielded a return.
Real Estate
The Company owns a multi-family housing complex in Gillette, Wyoming that had an occupancy rate of 94% at June 30, 2010, up from 80% at December 31, 2009. We also have real estate rental income from property located in Riverton, Wyoming. Real Estate revenues are approximately $208,000 per month and net cash flow from real estate is approximately $104,000 per month.
Although the multi-family housing project is pledged as collateral for the Company’s $10 million line of credit, there is no debt against the property. The Company may seek long term financing on the multi-family housing property in the future to further its oil and gas exploration and development projects.
Index
-26-
Commercial Bank
In January 2010, the Company entered into a $10.0 million line of credit with a commercial bank. No borrowings have been made under this line of credit as of the date of this report. The line of credit has a variable interest rate which is tied to a national market rate with a minimum interest rate of 5.5%. The line of credit is available until January 31, 2011 at which time it may be renewed depending on the financial strength and needs of the Company. The credit line is secured by the Company’s multifamily housing project and a corporate aircraft.
Capital Requirements
The direct capital requirements of the Company during the balance of 2010 are the funding of the drilling and completion of six to seven additional wells with Brigham in the Williston Basin, additional oil and gas exploration and development projects, acquisition of prospective oil and gas properties and/or existing production, operating and capital improvement costs of the water treatment plant at the Mount Emmons molybdenum project, operations at Remington Village, possible additional funding of geothermal operations and general and administrative costs.
Oil and Gas Exploration and Development
Bakken – Williston Basin, North Dakota
Under its agreement with Brigham, the Company is committed to drill and complete an additional four wells in the Williston Basin during 2010. Additionally, Brigham intends to drill and USE has committed to drill and complete two infill Bakken formation wells and a Three Forks formation test well. The Company projects expenditures of $13.2 million for these combined activities. The actual amount expended on the six wells will vary from the budgeted amount as a result of larger or smaller ownership interests of Brigham. Other factors which can cause actual amounts spent to vary from budgeted amounts are drilling conditions, problems encountered on site and weather. The wells to be drilled in 2010 will be approximately 10,000 feet in depth with 10,000 foot laterals and each well is expected to be completed with 28 to 32 frac stages. Projected 8/8ths cost for each of the remaining wells is $7.6 million for the Bakken formation wells and up to $8.9 million for the Three Forks formation test.
By electing to participate in all of the initial wells available to us, we have earned the rights to drill up to 15 additional wells in the Bakken formation and an additional 30 wells in the Three Forks formation, for a total of 60 wells, if the state of North Dakota allows two wells per formation in each spacing unit. If the spacing is ultimately increased to three wells per 1,280 acre spacing unit, the potential number of drilling locations could increase to 90. Working interests earned will vary according to Brigham’s initial working interest in each 1,280 acre drilling unit, after-payout provisions and the provisions governing each stage of the program. At our current and projected drilling rates, we expect that it will take four to six years to drill all of the wells in these units.
Gulf Coast
The Company has committed to spend $1.1 million in completion costs for its 50% ACP working interest in the ALMI #8 well that was drilled during the second quarter of 2010 with PetroQuest Energy, Inc. (“PetroQuest”). The well is expected to be completed during the third quarter of 2010. Weather and down hole problems can cause wells in this area to cost more than anticipated. The Company has drilled one successful gas well and three dry holes with PetroQuest. The Company may elect to participate in additional wells with PetroQuest during 2010.
Index
-27-
The Company has committed to spend $1.5 million to drill up to five inland oil and gas wells with Houston Energy L.P. (“Houston Energy”) in the Permian Basin in 2010. These wells have a lower risk of weather challenges due to the fact that they are inland. Drilling of these wells is expected to commence during the third quarter of 2010.
The Company plans on spending $1.5 million to drill four additional wells and maintain leases as well as complete interpretation of seismic data with Yuma Exploration Company, Inc. (“Yuma”) in 2010.
Other
The Company has a remaining budget of $180,000 for the maintenance of oil and gas leases during the balance of 2010 as well as $15.0 million for the acquisition of either prospective oil and gas properties or existing production.
Mount Emmons Molybdenum Property
Under the terms of its agreement with Thompson Creek Metals Company USA (“TCM”), the Company is responsible for all costs associated with operating the water treatment plant at the Mount Emmons molybdenum property. Operating costs during the balance of 2010 are projected to be approximately $901,000. Included in the operating costs, the Company participates on a 50 – 50 basis with TCM to fund holding costs associated with a parcel of jointly purchased real estate in Colorado and other nominal project related maintenance and security costs at the mine site. Additionally, the Company projects capital improvement expenditures of $1.3 million at the water treatment plant which are expected to improve its efficiency. Actual future costs could be different from those estimates made above.
Geothermal Energy Projects
The Company had an investment of $3.0 million in a geothermal company, SST, as of December 31, 2009, representing an ownership interest of 23.8%. This investment was increased by equity income of $1.1 million during the six months ended June 30, 2010, and decreased from a capital distribution from SST of $1.1 million. Because of the equity income and capital distribution being equal, the net investment in SST at June 30, 2010 remains at $3.0 million. As a result of not funding a cash call in the first quarter of 2010, the Company’s ownership interest of SST was reduced from 23.8% to 22.8%.
SST plans on continuing its temperature gradient drilling and the acquisition of additional prospective geothermal properties during 2010. The Company has not budgeted any capital resources for further investment in SST during 2010 but may elect to participate in cash calls during the year. The Company is not obligated to fund cash calls and will suffer further dilution if it elects not to fund.
Insurance
We have liability insurance coverage in amounts deemed sufficient and in line with industry standards for the location, stage, and type of operations in oil and gas, mineral property development (the Mt. Emmons molybdenum project), and the Remington Village housing complex. 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.
Index
-28-
Reclamation Costs
At June 30, 2010, there were no reclamation projects at the Company’s mineral or oil and gas properties that would require the expenditure of cash reserves during the balance of 2010.
Results of Operations
Three Months Ended June 30, 2010 compared to 2009
The Company recorded a net loss after taxes of $130,000, or less than a penny per share basic and diluted, for the quarter ended June 30, 2010 as compared to a net loss after taxes of $2.9 million, or $0.13 per share basic and diluted, during the quarter ended June 30, 2009.
The primary reasons for the loss during the quarter ended June 30, 2010 as compared to the quarter ended March 31, 2010 are:
|
·
|
Dry hole costs of $3.4 million during the quarter ended June 30, 2010. As a result of the dry hole costs during the quarter, the Company added approximately $3.4 million to the full cost pool which is being amortized over production. The addition of these dry hole costs raised the DD&A amount from $19.43 per barrel during the quarter ended March 31, 2010 to $23.98 per barrel during the quarter ended June 30, 2010.
|
|
·
|
Lower proven reserves on wells drilled during the quarter ended June 30, 2010.
|
|
·
|
Higher drilling and completion costs due to increased drilling activity in the Williston Basin which has impacted rig availability.
|
|
·
|
Operating costs for the Bakken wells were higher during the quarter due to work over costs. During the workovers of the wells, they did not produce oil or gas.
|
The Company recognized $6.8 million in revenues during the quarter ended June 30, 2010 as compared to revenues of $1.5 million during same period in the prior year. Tabular representation of the increases in revenues as well as the income (loss) from operations for the quarters ended June 30, 2010 and 2009 is as follows:
|
(In thousands)
|
||||||||
|
For the three months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Revenues
|
$ | 6,826 | $ | 1,499 | ||||
|
Operating expenses
|
4,343 | 2,712 | ||||||
|
Depreciation, depletion and amortization
|
2,774 | 981 | ||||||
|
Impairment
|
-- | -- | ||||||
| 7,117 | 3,693 | |||||||
|
Operating income (loss)
|
$ | (291 | ) | $ | (2,194 | ) | ||
Revenues for the second quarter of 2010 are 355% higher than revenues for the second quarter of 2009. The increase is primarily a result of the Company’s production of oil and gas in the Williston Basin. The increased expenses are a result of work over costs and depletion recognized on the increased oil production during the quarter.
Index
-29-
Oil and gas production from the Williston Basin has increased revenue trends and as additional wells are drilled and completed during 2010 it is believed that this trend will continue. The Company has experienced a 100% completion rate on wells drilled in the Williston Basin with good initial production flows. Future wells may not perform as well. The multi stage frac completion techniques used by the Company and Brigham are relatively new which makes long term production projections uncertain. The Company relies on professional third party reserve engineers to calculate decline curves.
Oil and gas operations produced net operating income of $2.3 million during the quarter ended June 30, 2010 as compared to a loss of $33,000 from oil and gas operations during the quarter ended June 30, 2009. The following table details the results of operations from the oil and gas sector for the quarters ended June 30, 2010 and 2009:
|
(In thousands)
|
||||||||
|
For the three months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Oil and gas revenues
|
$ | 6,218 | $ | 754 | ||||
|
Operating expenses
|
1,498 | 180 | ||||||
|
Depreciation, depletion and amortization
|
2,396 | 607 | ||||||
|
Impairment
|
-- | -- | ||||||
| 3,894 | 787 | |||||||
|
Operating income (loss)
|
$ | 2,324 | $ | (33 | ) | |||
The following table summarizes production volumes, average sales prices and operating revenues for the quarters ended June 30, 2010 and 2009:
|
Three Months Ended
|
||||||||||||
|
June 30,
|
Increase
|
|||||||||||
|
2010
|
2009
|
(Decrease)
|
||||||||||
|
Production volumes
|
||||||||||||
|
Oil and condensate (Bbls)
|
72,601 | 3,484 | 69,117 | |||||||||
|
Natural gas (Mcf)
|
163,996 | 114,499 | 49,497 | |||||||||
|
Average sales prices
|
||||||||||||
|
Oil and condensate (per Bbl)
|
$ | 71.98 | $ | 59.13 | $ | 12.85 | ||||||
|
Natural gas (per Mcf)
|
6.05 | 4.13 | 1.92 | |||||||||
|
Operating revenues (in thousands)
|
||||||||||||
|
Oil and condensate
|
$ | 5,226 | $ | 229 | $ | 4,997 | ||||||
|
Natural gas
|
992 | 473 | 519 | |||||||||
|
Total operating revenue
|
6,218 | 702 | 5,516 | |||||||||
|
Lease operating expense
|
(664 | ) | (71 | ) | (593 | ) | ||||||
|
Production taxes
|
(834 | ) | (57 | ) | (777 | ) | ||||||
|
Gain before DD&A
|
4,720 | 574 | 4,146 | |||||||||
|
DD&A
|
(2,396 | ) | (607 | ) | (1,789 | ) | ||||||
|
Gain (Loss)
|
$ | 2,324 | $ | (33 | ) | $ | 2,357 | |||||
Index
-30-
Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids (“NGL”) that are sold separately from the remaining natural gas. We sell some of our processed 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 NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.
The Company plans to drill and complete an additional six to seven wells (including two infill wells and one Three Forks formation test well) in the Williston Basin during 2010. Factors that could affect the income from operations in the balance of 2010 on wells to be drilled are:
·
Lower working interests in the wells due to lower ownership interest in the leases held by Brigham
·
Brigham has elected to participate at 50% in each remaining well which will reduce both the cost to the Company as well as the revenues if the wells are successful
·
Lower market prices for oil and gas during 2010
·
Higher drilling and operating expenses
·
Steeper decline rates than currently anticipated
·
Mechanical and geological problems with the wells
The Company’s other revenue producing sector is commercial real estate. A breakdown of the income from operations from commercial real estate is contained in the following table:
|
(In thousands)
|
||||||||
|
For the three months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Real estate revenues
|
$ | 608 | $ | 745 | ||||
|
Operating expenses
|
336 | 209 | ||||||
|
Depreciation, depletion and amortization
|
266 | 289 | ||||||
| 602 | 498 | |||||||
|
Operating income
|
$ | 6 | $ | 247 | ||||
The decline in revenues for the quarter ended June 30, 2010 as compared to the same period of the prior year is primarily as a result of lower rental rates at Remington Village. Occupancy rates were approximately 91% at June 30, 2009 and 94% at June 30, 2010. Operating expenses increased as a result of the Company’s multifamily housing project reaching maturity which added additional expenses to the grounds maintenance and ongoing maintenance of apartment units when property damage occurs or tenants move out.
Index
-31-
Mount Emmons Molybdenum Property -
When the Company entered into its agreement with TCM, it agreed to pay all costs associated with the water treatment plant at the Mount Emmons molybdenum property and thereby recorded $459,000 in costs and expenses for that facility and a credit of $5,000 in holding costs of the Mt. Emmons molybdenum property during the quarter ended June 30, 2010. During the quarter ended June 30, 2009, the Company expended $576,000 in operating costs related to the water treatment plant.
General Administrative -
General and administrative expenses increased by $335,000 during the quarter ended June 30, 2010 over those experienced at during the quarter ended June 30, 2009. The increase is as a result of:
|
·
|
$329,000 accrual of a 2010 year-end bonus to all employees of the Company which is subject to meeting corporate and personal goals, meeting annual budget goals, increased share price and cash flow from operations. Under the Performance Compensation Plan (“PCP”) adopted by the board of directors, employees can earn from 33% to 100% of their base compensation as bonuses if the terms of the PCP are met. The PCP was proposed by the Company’s Compensation Committee and adopted by the full Board in April 2009. Details of the PCP are disclosed in the Company’s annual proxy statement for the annual meeting that was held in June of 2010. Any bonus earned for 2010 performance will be paid during the first quarter of 2011. The PCP is being reevaluated by the Board of Directors and is subject to change. Any change to the PCP may affect the accrued amounts. As of June 30, 2009 no accrual had been made as the terms of the PCP had not been met.
|
Other income and expenses
- The Company recorded an equity gain of $179,000 from its investment in SST during the quarter ended June 30, 2010. The Company recorded an equity loss of $75,000 for the quarter ended June 30, 2009. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce the Company’s investment to zero or the Company sells its investment.
Interest income decreased from $44,000 during the quarter ended June 30, 2009 to $22,000 during the quarter ended June 30, 2010. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the quarter, and lower interest rates received on those investments.
Interest expense of $18,000 during the quarter ended June 30, 2010 and $20,000 during the quarter ended June 30, 2009 was related primarily to the financing of a property purchased with TCM near the Mount Emmons property.
The Company therefore recorded net loss after taxes of $130,000, or less than a penny per share basic and diluted, during the quarter ended June 30, 2010 as compared to a net loss after taxes of $2.9 million, or $0.13 per share basic and diluted, during the quarter ended June 30, 2009.
Six Months Ended June 30, 2010 compared to 2009
The Company recorded net income after taxes of $1.4 million, or $0.05 per share basic and diluted, for the six months ended June 30, 2010 as compared to a net loss after taxes of $5.2 million, or $0.24 per share basic and diluted, during the six months ended June 30, 2009.
The Company recognized $15.2 million in revenues during the six months ended June 30, 2010 as compared to revenues of $2.9 million during same period in the prior year. Tabular representation of the increases in revenues as well as the income (loss) from operations for the six month periods ended June 30, 2010 and 2009 is as follows:
Index
-32-
|
(In thousands)
|
||||||||
|
For the six months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Revenues
|
$ | 15,174 | $ | 2,907 | ||||
|
Operating expenses
|
8,721 | 5,395 | ||||||
|
Depreciation, depletion and amortization
|
5,408 | 2,070 | ||||||
|
Impairment
|
-- | 1,063 | ||||||
| 14,129 | 8,528 | |||||||
|
Operating income (loss)
|
$ | 1,045 | $ | (5,621 | ) | |||
Revenues for the first six months of 2010 are 422% higher when compared to the first six months of 2009. The increase is primarily a result of the Company’s production of oil and gas in the Williston Basin. The increased expenses are a result of the increased depletion recognized on the increased oil and gas production during the current period. During the six months ended June 30, 2009, the Company recorded an impairment of $1.1 million on its oil and gas operations due to depressed oil and gas prices during the first quarter of 2009 and only one producing well over which to spread the entire exploration cost. As a result of increased oil and gas prices during the first six months of 2010 and additional reserves to amortize the full cost pool over, no impairment was required during the six months ended June 30, 2010.
Oil and gas production from the Williston Basin has increased revenue trends and as additional wells are drilled and completed during the remainder of 2010 it is believed that this trend will continue. The Company has experienced a 100% completion rate on wells drilled in the Williston Basin with good initial production flows. Future wells may not perform as well. The multi stage frac completion techniques used by the Company and Brigham are relatively new which makes long term production projections uncertain. The Company relies on professional third party reserve engineers to calculate decline curves.
Oil and gas operations produced net operating income of $6.7 million during the six months ended June 30, 2010 as compared to a loss of $1.2 million from oil and gas operations during the six months ended June 30, 2009. The following table details the results of operations from the oil and gas sector for the six months ended June 30, 2010 and 2009:
|
(In thousands)
|
||||||||
|
For the six months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Oil and gas revenues
|
$ | 13,927 | $ | 1,428 | ||||
|
Operating expenses
|
2,628 | 279 | ||||||
|
Depreciation, depletion and amortization
|
4,651 | 1,320 | ||||||
|
Impairment
|
-- | 1,063 | ||||||
| 7,279 | 2,662 | |||||||
|
Operating income (loss)
|
$ | 6,648 | $ | (1,234 | ) | |||
Index
-33-
The following table summarizes production volumes, average sales prices and operating revenues for the six month periods ended June 30, 2010 and 2009:
|
Six Months Ended
|
||||||||||||
|
June 30,
|
Increase
|
|||||||||||
|
2010
|
2009
|
(Decrease)
|
||||||||||
|
Production volumes
|
||||||||||||
|
Oil and condensate (Bbls)
|
160,927 | 7,100 | 153,827 | |||||||||
|
Natural gas (Mcf)
|
330,398 | 230,877 | 99,521 | |||||||||
|
Average sales prices
|
||||||||||||
|
Oil and condensate (per Bbl)
|
$ | 73.30 | $ | 38.15 | $ | 35.15 | ||||||
|
Natural gas (per Mcf)
|
6.45 | 4.94 | 1.51 | |||||||||
|
Operating revenues (in thousands)
|
||||||||||||
|
Oil and condensate
|
$ | 11,796 | $ | 371 | $ | 11,425 | ||||||
|
Natural gas
|
2,131 | 1,057 | 1,074 | |||||||||
|
Total operating revenue
|
13,927 | 1,428 | 12,499 | |||||||||
|
Lease operating expense
|
(868 | ) | (170 | ) | (698 | ) | ||||||
|
Production taxes
|
(1,760 | ) | (109 | ) | (1,651 | ) | ||||||
|
Impairment
|
- | (1,063 | ) | 1,063 | ||||||||
|
Gain before DD&A
|
11,299 | 86 | 11,213 | |||||||||
|
DD&A
|
(4,651 | ) | (1,320 | ) | (3,331 | ) | ||||||
|
Gain (Loss)
|
$ | 6,648 | $ | (1,234 | ) | $ | 7,882 | |||||
Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids (“NGL”) that are sold separately from the remaining natural gas. We sell some of our processed 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 NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.
The Company plans to drill and complete an additional six to seven wells (including two infill wells and one Three Forks formation test well) in the Williston Basin during 2010. Factors that could affect the income from operations in the balance of 2010 on wells to be drilled are:
·
Lower working interests in the wells due to lower ownership interest in the leases held by Brigham
·
Brigham has elected to participate at 50% in these wells which will reduce both the cost to the Company as well as the revenues if the wells are successful
·
Lower market prices for oil and gas during 2010
·
Higher drilling and operating expenses
·
Steeper decline rates than currently anticipated
·
Mechanical and geological problems with the wells
Index
-34-
The Company’s other revenue producing sector is commercial real estate. A breakdown of the income from operations from commercial real estate is contained in the following table:
|
(In thousands)
|
||||||||
|
For the six months ending
|
||||||||
|
June 30, 2010
|
June 30, 2009
|
|||||||
|
Real estate revenues
|
$ | 1,247 | $ | 1,479 | ||||
|
Operating expenses
|
624 | 489 | ||||||
|
Interest expense
|
-- | 19 | ||||||
|
Depreciation, depletion and amortization
|
531 | 521 | ||||||
| 1,155 | 1,029 | |||||||
|
Operating income
|
$ | 92 | $ | 450 | ||||
The decline in revenues for the six months ended June 30, 2010 as compared to the same period of the prior year is as a result of lower average rental and occupancy rates during the six months ended June 30, 2010. Occupancy rates were approximately 91% at June 30, 2009 and 94% at June 30, 2010. The occupancy rate has increased from 80% at December 31, 2009 to the current occupancy of 94%. Operating expenses increased as a result of the Company’s multifamily housing project reaching maturity which added additional expenses to the grounds maintenance and ongoing maintenance of apartment units when property damage occurs or tenants move out.
Mount Emmons Molybdenum Property -
When the Company entered into its agreement with TCM, it agreed to pay all costs associated with the water treatment plant at the Mount Emmons molybdenum property and thereby recorded $808,000 in costs and expenses for that facility and $52,000 in holding costs of the Mt. Emmons molybdenum property during the six months ended June 30, 2010. During the six months ended June 30, 2009, the Company expended $1.0 million in operating costs related to the water treatment plant.
General Administrative -
General and administrative expenses increased by $998,000 during the six months ended June 30, 2010 over those experienced at during the six months ended June 30, 2009. The increase is as a result of:
|
·
|
$676,000 - Accrual of a 2010 year-end bonus to all employees of the Company which is subject to meeting corporate and personal goals, meeting annual budget goals, increased share price and cash flow from operations. Under the Performance Compensation Plan (“PCP”) adopted by the board of directors, employees can earn from 33% to 100% of their base compensation as bonuses if the terms of the PCP are met. The PCP was proposed by the Company’s Compensation Committee and adopted by the full Board in April, 2009. Details of the PCP are disclosed in the Company’s annual proxy statement for the annual meeting that was held in June of 2010. Any bonus earned for 2010 performance will be paid during the first quarter of 2011. The PCP is being reevaluated by the Board of Directors and is subject to change. Any change to the PCP may affect the accrued amounts. As of June 30, 2009 no accrual had been made as the terms of the PCP had not been met;
|
|
·
|
$198,000 - Noncash increase in stock compensation expense. The increase is primarily due to shares issued to officers of the Company pursuant to the 2001 Stock Compensation Plan being issued at a higher price than those issued in 2009; and
|
Index
-35-
|
·
|
$139,000 - Increase in professional services. This increase is primarily due to professional services fees related to our participation in the Williston Basin wells with Brigham and with services related to our listing on NASDAQ.
|
Other income and expenses
– As a result of the sale of two of Standard Steam Trust’s geothermal properties, the Company recorded an equity gain of $1.1 million from its investment in SST during the six months ended June 30, 2010. The Company recorded an equity loss of $166,000 for the six months ended June 30, 2009. Equity losses from the investment in SST are expected to continue until such time as additional SST properties are sold, equity losses reduce the Company’s investment to zero or the Company sells its investment.
The Company recorded a gain on sale of assets of $115,000 during the six months ended June 30, 2010. The gain was primarily related to the sale of an office building that the Company previously held as rental property. The Company recorded a gain on sale of assets of $5,000 during the six months ended June 30, 2009.
Interest income decreased from $176,000 during the six months ended June 30, 2009 to $61,000 during the six months ended June 30, 2010. The decrease is a result of lower amounts of cash invested in interest bearing instruments and lower interest received on those investments.
Interest expense of $35,000 during the six months ended June 30, 2010 was related primarily to the financing of a property purchased with TCM near the Mount Emmons property. Interest expense of $58,000 during the six months ended June 30, 2009 related primarily to the construction loan for Remington Village which was fully repaid in January 2009 and the financing of a property purchased with TCM near the Mount Emmons property.
The Company therefore recorded net income after taxes of $1.4 million, or $0.05 per share basic and diluted, during the six months ended June 30, 2010 as compared to a net loss after taxes of $5.2 million, or $0.24 per share basic and diluted, during the six months ended June 30, 2009.
Critical Accounting Policies
For detailed descriptions of Company’s significant accounting policies, please see pages 67 to 70 of the Company’s Annual Report on Form 10K for the year ended December 31, 2009.
Mineral Properties
- The Company capitalizes 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 the Company subsequently determines 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 June 30, 2010 and December 31, 2009 reflect capitalized costs associated with the Company’s Mount Emmons molybdenum property near Crested Butte, Colorado. The Company has entered into an agreement with TCM to develop this property. TCM may earn up to a 75% interest in the project for the investment of $400 million. The Company has received two of the six anticipated annual payments in the amount of $1.0 million each. These payments were applied as a reduction of the Company’s investment in the Mount Emmons property.
Index
-36-
Molybdenum prices declined from a ten year high average price of $34.13 per pound in July 2008 to a ten-year low average price of $8.02 per pound in April 2009. During the first six months of 2010, the spot price for molybdenum increased to a high of $19.00 per pound in April 2010 and was $14.75 per pound at June 30, 2010.
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.
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 of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to tax assets directly attributable to 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.
Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at June 30, 2010 and December 31, 2009 which were not included in the amortized cost pool were $13.2 million and $5.4 million, respectively. These costs consist of wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs
and are related to unproved properties. No capitalized costs related to unproved properties are included in the amortization base at June 30, 2010 and December 31, 2009. It is anticipated that these costs will be added to the full cost amortization pool in the next two years as properties are proved, drilled or abandoned.
Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change. If oil or natural gas prices decline substantially, even for only a short period of time, or if we have downward revisions to our
estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.
Index
-37-
Long Lived Assets - Real Estate -
The Company evaluates its long-lived assets, which consist of commercial real estate, for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. Impairment calculations are based on market appraisals. If rental rates decrease or costs increase to levels that result in estimated future cash flows, on an undiscounted basis, that are less than the carrying amount of the related asset, an asset impairment is considered to exist. Changes in significant assumptions underlying future cash flow estimates may have a material effect on the Company's financial position and results of operations. The Company does not obtain appraisals on an ongoing basis for the property. The Company however did obtain an appraisal in 2009. Rental property conditions have not changed significantly in the area of the Company’s property. At June 30, 2010 and December 31, 2009, management determined that no impairment existed on the Company’s long-lived asset as the 2009 appraised value exceeded construction and carrying value and rental rates remained strong and costs within projected limits.
Asset Retirement Obligations -
The Company accounts for its asset retirement obligations under ASC 410-20. The Company records the fair value of the reclamation liability on its inactive mining properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required as well as accretes the liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for reclamation during the quarter in which it occurs.
Future Operations
Management intends to continue seeking investment opportunities presented by the recent and future projected market prices for oil and natural gas. Long term, we intend to be prepared to pay our share of the holding and development costs associated with the Mount Emmons property.
Effects of Changes in Prices
Mineral operations are significantly affected by changes in commodity prices. As prices for a particular mineral increase, values for prospects for that mineral typically also increase, making acquisitions of such properties more costly and sales potentially more valuable. Conversely, a price decline could enhance acquisitions of properties containing that mineral, but could also make sales of such properties more difficult. Operational impacts of changes in mineral commodity prices are common in the mining and oil and gas industries.
At June 30, 2010, the Company is receiving revenues from its oil and gas business. The Company’s revenues, cash flows, future rate of growth, results of operations, financial condition and ability to finance projected acquisition of oil and gas producing assets are dependent upon prevailing prices of oil and gas.
The Company’s multifamily housing revenues could be affected negatively if there was a sustained down turn in the price of coal, oil and natural gas which could affect the demand for housing in the Gillette, Wyoming area.
Index
-38-
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 (the “Securities Act”), 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. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil 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 business. In particular, careful consideration should be given to cautionary statements made in the Company’s Risk Factors included in its Annual Report on Form 10-K and quarterly reports on Form 10-Q filed with the SEC. The Company undertakes no duty to update or revise these forward-looking statements.
When used in this Form 10-Q, the words, “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. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10-Q.
Off-Balance Sheet Arrangements
None.
Contractual Obligations
We had three divisions of contractual obligations at June 30, 2010: Debt to third parties of $800,000 with interest at 6% per annum, executive retirement of $983,500 and asset retirement obligations of $234,000. The debt will be paid over a period of four years. The executive retirement liability will paid out over varying periods starting after the actual retirement dates of the covered executives. The asset retirement obligations will be retired during the next 34 years. The following table shows the scheduled debt payment and expenditures for budgeted asset retirement obligations:
Index
-39-
|
(In thousands)
|
||||||||||||||||||||
|
Payments due by period
|
||||||||||||||||||||
|
Less
|
One to
|
Three to
|
More than
|
|||||||||||||||||
|
than one
|
Three
|
Five
|
Five
|
|||||||||||||||||
|
Total
|
Year
|
Years
|
Years
|
Years
|
||||||||||||||||
|
Long-term debt obligations
|
$ | 800 | $ | 200 | $ | 600 | $ | -- | $ | -- | ||||||||||
|
Executive retirement
|
$ | 983 | 153 | 129 | -- | 701 | ||||||||||||||
|
Asset retirement obligation
|
$ | 234 | -- | -- | 26 | 208 | ||||||||||||||
|
Totals
|
$ | 2,017 | $ | 353 | $ | 729 | $ | 26 | $ | 909 | ||||||||||
None
Evaluation of Disclosure Controls and Procedures
As of June 30, 2010, 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 Securities and Exchange Act of 1934, as amended (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 June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Index
-40-
Water Rights Litigation –Mount Emmons Molybdenum Property
1.
Concerning the Application of the United States of America in the Gunnison River, Gunnison County
, Case No. 99CW267. This case involves an application filed by the United States of America to appropriate 0.033 cubic feet per second of water for wildlife use and for incidental irrigation of riparian vegetation at the Mount Emmons Iron Bog Spring, located in the vicinity of Mount Emmons. MEMCO filed a Statement of Opposition to protect proposed mining operations against any adverse impacts by the water requirements of the Iron Bog on such operations. This case is pending while the parties attempt to reach a settlement on the proposed decree terms and conditions.
2.
Concerning the Application of U.S. Energy
, Case No. 2008CW81. On July 25, 2008, the Company filed an Application for Finding of Reasonable Diligence with the Water Court (“Water Diligence Application”) concerning the conditional water rights associated with Mount Emmons (Case No. 2008CW81). The conditional water decree (“Decree”) requires 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 2002 Decree, or within six years of the final determination in the Applicant’s pending patent application, whichever occurs 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 upholding BLM’s issuance of the mineral patents.
The Company believes that the deadline for filing the plan of operations specified by the Decree is April 30, 2013 (six years from the final determination of issuance of the mineral patents by the United States Supreme Court). The Forest Service has indicated that the deadline should be April 2, 2010 (six years from the issuance of the mineral patents by BLM). The United States, on behalf of the Forest Service and BLM, filed a Statement of Opposition on this specific issue only. Statements of Opposition were also filed by six other parties including the City of Gunnison, the Colorado Water Conservation Board, High Country Citizens’ Alliance, Crested Butte Land Trust and others for various reasons, including requesting the Company be put on strict proof as to demonstrating evidence of reasonable diligence in developing the conditional water rights.
On March 26, 2010, BLM and the Forest Service signed a Stipulation with the Company, which resolved their opposition to the Company’s Water Diligence Application. Pursuant to the Stipulation, the Company agreed to prepare, in consultation with the BLM and Forest Service, and file no later than April 2, 2010, an Initial Plan of Operations in accordance with 36 C.F.R. Sec. 228.4(d). BLM, the Forest Service and the Company also agreed the filing of this Plan of Operations would satisfy the Decree. The Company filed the Initial Plan of Operations on March 31, 2010.
Index
-41-
Appeal of Approval of Notice of Intent to Conduct Prospecting for the Mount Emmons Property
On March 8, 2008, High Country Citizens’ Alliance (‘HCCA”) filed a request for hearing before the Colorado Land Reclamation Board (“Board”) of the approval of a Notice of Intent to Conduct Prospecting Notice for the Mount Emmons molybdenum property (“NOI”), which was approved by the Division of Reclamation, Mining and Safety of the Colorado Department of Natural Resources (“DRMS”) on January 3, 2008. The NOI as approved provided for continued exploration of the molybdenum deposit to update, improve and verify, in accordance with current industry standards and legal requirements, mineralization data that was collected by Amax in the late 1970’s. On May 14, 2008, the Board denied HCCA’s Request for Hearing and also denied their Request for a Declaratory Order. Citing Colorado law, the Board determined that HCCA did not have standing or the right to appeal DRMS’s approval of the NOI under Colorado law. On August 28, 2008, HCCA appealed the Board’s decision in Denver District Court.
Plaintiff: High Country Citizen’s Alliance v. Defendants: Colorado Mined Land Reclamation Board, Colorado Division of Reclamation Mining and Safety and U.S. Energy Corp.,
Case No.: 08CV6156 (District Court, 2d Jud. Dist., City and County of Denver). The Board has filed an answer with the Court. The DRMS and the Company (in conjunction with TCM) have both filed the responsive pleadings in addition to motions to dismiss the HCCA complaint.
No hearing date has yet been scheduled in the District Court of Colorado concerning the Colorado Division of Reclamation, Mining, and Safety’s issuance of a Notice of Intent to Conduct Prospecting to the Company for the Mount Emmons Property.
For information on other legal proceedings in which there have been no new developments since June 30, 2010, see Item 1, Part II of the Company’s Annual Report on Form 10-K filed on March 12, 2010.
The Company is disclosing a new material change to the risk factors discussed in Part I, “Item 1A. Risk Factors” (pages 14 to 27) in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 which could 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.
Insurance may be insufficient to cover future liabilities. Our business is focused in three areas, each of which presents potential liability exposure: Oil and gas exploration and development; permitting and limited exploration of the Mt. Emmons molybdenum property; and a residential multi-family housing complex in Gillette, Wyoming. We also have potential exposure in connection with the Company’s corporate aircraft and general liability and property damage associated with the ownership of other corporate assets. We rely on the operators of our oil and gas and mineral properties to obtain and maintain liability insurance for our working interest in the properties. We maintain insurance policies for the liability of and damage to our multifamily housing complex, corporate aircraft and general corporate assets
.
We also have separate policies for liability and environmental exposures of the water treatment plant at the Mt. Emmons project. These policies provide coverage for bodily injury and property damage as well as costs to remediate events adversely impacting the environment.
Index
-42-
We would be liable for claims in excess of coverage. If uncovered liabilities are substantial, payment thereof could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. As of the date of this Report, we know of no claims related to any of our properties.
During the six months ended June 30, 2010, the Company issued a total of 40,000 shares of its common stock. The shares were issued as restricted securities in reliance on the exemption available to the Company under Section 4(2) of the Securities Act of 1933. These shares were issued as new issuances pursuant to the 2001 stock compensation plan.
Not Applicable
U.S. Energy Corp. (the “Company”) held its annual meeting of shareholders on Friday, June 25, 2010, at 10:00 a.m. Mountain Time in Riverton, Wyoming. The certified results of the matters voted upon at the meeting, which are more fully described in the Company’s annual proxy statement, are as set forth below:
The following nominees for directors were elected by a plurality of votes cast to serve until the terms stated in the Company’s proxy statement filed on Schedule 14A, with the Securities and Exchange Commission on April 29, 2010 (until the 2013 Annual Meeting of Shareholders and until their successors are elected or appointed and qualified):
|
Name of Director
|
Votes For
|
Withheld
|
Broker Non-Votes
|
|||
|
Stephen V. Conrad
|
7,322,244
|
581,286
|
12,019,005
|
|||
|
Mark J. Larsen
|
7,268,168
|
635,362
|
12,019,005
|
The shareholders also voted on the ratification of appointment of Hein & Associates LLP, as independent auditors for the fiscal year:
|
Votes For
|
Votes Against
|
Abstain
|
Broker Non-Votes
|
|||
|
19,291,602
|
551,196
|
79,737
|
0
|
Not Applicable
Index
-43-
|
(a)
|
Exhibits
|
||
|
10.1
31.1
|
Consent of Cawley, Gillespie & Associates, Inc.
Certification of Chief Executive Officer Pursuant to Rule 13a-15(e) / Rule 15d-15(e)
|
||
|
31.2
|
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) / Rule 15(e)/15d-15(e)
|
||
|
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
|
||
|
(b)
|
Reports on Form 8-K.
The Company filed seven reports on Form 8-K for the quarter ended June 30, 2010. The events reported were as follows:
|
||
|
1.
|
The report filed on April 5, 2010, under Item 7.01 referenced the initial production rate of the Jack Erickson 6-31 #1H well.
|
||
|
2.
|
The report filed on April 12, 2010, under Item 7.01 referenced the company presenting at the IPAA Oil & Gas Investment Symposium in New York.
|
||
|
3.
|
The report filed on April 27, 2010, under Item 7.01 referenced results from two drilled prospects with PetroQuest Energy, L.L.C.; well results from initial test well with Yuma Exploration and Production Company; expansion of drilling program with PetroQuest and Houston Energy, L.P. and update on Williston Basin.
|
||
|
4.
|
The report filed on April 28, 2010, under Item 7.01 referenced a cash distribution of $1.1 million from Standard Steam Trust.
|
||
|
5.
|
The report filed on May 10, 2010, under Item 7.01 referenced a conference call on May 10, 2010 to review and discuss first quarter 2010 highlights and financial results.
|
||
|
6.
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The report filed on June 24, 2010, under Item 7.01 referenced an update on oil and gas drilling initiatives.
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||
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7.
|
The report filed on June 29, 2010, under Item 5.07 referenced the voting results from the annual meeting of shareholders.
|
||
Index
-44-
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
U.S. ENERGY CORP.
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|||
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(Registrant)
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|||
|
Date: August 9, 2010
|
By:
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/s/ Keith G. Larsen
|
|
|
KEITH G. LARSEN
|
|||
|
Chairman and CEO
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|||
|
Date: August 9, 2010
|
By:
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/s/ Robert Scott Lorimer
|
|
|
ROBERT SCOTT LORIMER
|
|||
|
Principal Financial Officer and
|
|||
|
Chief Accounting Officer
|
|||
Index
-45-
TABLE OF CONTENTS
Part I. Financial InformationItem 1. Financial StatementsItem 2. Management's Discussion and Analysis Of Financial Condition and Results Of OperationsItem 3 . Quantitative and Qualitative Disclosures About Market RiskItem 4 . Controls and ProceduresPart II. Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 2 . Unregistered Sales Of Equity Securities and Use Of ProceedsItem 3. Defaults Upon Senior SecuritiesItem 4 . Submission Of Matter To A Vote Of Security HoldersItem 5 . Other InformationItem 6. Exhibits