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 September 30, 2013 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 Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
YES
x
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.
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Large accelerated filer
o
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Accelerated filer
x
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Non-accelerated filer
o
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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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 November 7, 2013 there were issued and outstanding 27,682,602 shares of the Company’s common stock, $0.01 par value.
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 (unaudited)
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Condensed Consolidated
Balance Sheets
as of September 30, 2013 and December 31, 2012
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4-5
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Condensed Consolidated Statements of
Operations
for the Three and Nine Months Ended September 30, 2013 and 2012
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6-7
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Condensed Consolidated Statements of
Comprehensive Income
(Loss) for the Three and Nine Months Ended September 30, 2013 and 2012
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8
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Condensed Consolidated Statements of
Cash Flows
for the Nine Months Ended September 30, 2013 and 2012
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9-10
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Notes
to Condensed Consolidated Financial Statements
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11-24
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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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25-38
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Item 3.
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Quantitative
and Qualitative Disclosures About Market Risk
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38-40
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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
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Item 1A.
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Risk
Factors
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41
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Item 2.
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Unregistered Sales
of Equity Securities and Use of Proceeds
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41
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Item 3.
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Defaults
Upon Senior Securities
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41
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Item 4.
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Mine
Safety Disclosures
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42
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Item 5.
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42
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Item 6.
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42
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43
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Certifications
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See Exhibits
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U.S. ENERGY CORP.
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ASSETS
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(Unaudited)
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(In thousands, except shares)
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September 30,
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December 31,
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2013
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2012
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Current assets:
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Cash and cash equivalents
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$ | 5,538 | $ | 2,825 | ||||
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Available for sale securities
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75 | 183 | ||||||
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Accounts receivable trade
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5,792 | 5,182 | ||||||
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Commodity risk management asset
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62 | 472 | ||||||
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Assets held for sale
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-- | 17,051 | ||||||
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Other current assets
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453 | 302 | ||||||
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Total current assets
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11,920 | 26,015 | ||||||
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Investment
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2,224 | 2,264 | ||||||
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Properties and equipment
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Oil & gas properties under full cost method,
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net of $53,333 and $43,454 accumulated
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depletion, depreciation and amortization
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84,513 | 85,634 | ||||||
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Undeveloped mining claims
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20,739 | 20,739 | ||||||
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Property, plant and equipment, net
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4,226 | 4,435 | ||||||
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Net properties and equipment
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109,478 | 110,808 | ||||||
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Other assets
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1,734 | 1,740 | ||||||
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Total assets
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$ | 125,356 | $ | 140,827 | ||||
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U.S. ENERGY CORP.
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CONDENSED CONSOLIDATED 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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September 30,
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December 31,
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2013
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2012
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Current liabilities:
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Accounts payable
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$ | 5,416 | $ | 2,692 | ||||
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Accrued compensation
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482 | 295 | ||||||
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Commodity risk management liability
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647 | -- | ||||||
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Current portion of debt
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200 | 200 | ||||||
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Liabilities held for sale
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-- | 10,022 | ||||||
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Other current liabilities
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69 | 44 | ||||||
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Total current liabilities
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6,814 | 13,253 | ||||||
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Long-term debt, net of current portion
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7,000 | 10,000 | ||||||
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Asset retirement obligations
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775 | 686 | ||||||
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Other accrued liabilities
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746 | 771 | ||||||
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Commitment and contingencies
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Shareholders' equity
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Common stock, $.01 par value; unlimited shares
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authorized; 27,682,602 and 27,652,602
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shares issued, respectively
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277 | 277 | ||||||
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Additional paid-in capital
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123,249 | 123,078 | ||||||
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Accumulated deficit
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(13,498 | ) | (7,339 | ) | ||||
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Other comprehensive (loss) income
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(7 | ) | 101 | |||||
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Total shareholders' equity
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110,021 | 116,117 | ||||||
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Total liabilities and shareholders' equity
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$ | 125,356 | $ | 140,827 | ||||
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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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Three months ended September 30,
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Nine months ended September 30,
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2013
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2012
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2013
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2012
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Oil, gas, and NGL production revenues:
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$ | 8,582 | $ | 7,639 | $ | 24,376 | $ | 24,496 | ||||||||
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Operating expenses:
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Oil and gas
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2,877 | 2,514 | 8,241 | 7,965 | ||||||||||||
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Oil and gas depreciation, depletion
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and amortization
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3,205 | 3,410 | 9,879 | 11,081 | ||||||||||||
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Impairment of oil and gas properties
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-- | -- | 5,828 | 523 | ||||||||||||
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Water treatment plant
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394 | 609 | 1,214 | 1,554 | ||||||||||||
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Mineral holding costs
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410 | 400 | 934 | 716 | ||||||||||||
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General and administrative
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1,337 | 1,659 | 3,963 | 5,313 | ||||||||||||
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Impairment of corporate aircraft
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-- | 1,756 | -- | 1,756 | ||||||||||||
| 8,223 | 10,348 | 30,059 | 28,908 | |||||||||||||
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Income (loss) from operations
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359 | (2,709 | ) | (5,683 | ) | (4,412 | ) | |||||||||
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Other income and expenses:
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Realized (loss) gain on risk
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management activities
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(307 | ) | 12 | (274 | ) | (137 | ) | |||||||||
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Unrealized (loss) gain on risk
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management activities
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(768 | ) | (478 | ) | (1,056 | ) | 1,233 | |||||||||
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Gain (loss) on the sale of assets
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19 | (21 | ) | 729 | (11 | ) | ||||||||||
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Equity gain (loss) in unconsolidated
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investment
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11 | (17 | ) | (40 | ) | (168 | ) | |||||||||
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Gain on sale of marketable securities
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-- | 28 | -- | 82 | ||||||||||||
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Miscellaneous income
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50 | 81 | 80 | 169 | ||||||||||||
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Interest income
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1 | 2 | 4 | 8 | ||||||||||||
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Interest expense
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(71 | ) | (53 | ) | (229 | ) | (128 | ) | ||||||||
| (1,065 | ) | (446 | ) | (786 | ) | 1,048 | ||||||||||
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Loss before income taxes
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and discontinued operations
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(706 | ) | (3,155 | ) | (6,469 | ) | (3,364 | ) | ||||||||
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U.S. ENERGY CORP.
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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
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(Unaudited)
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(In thousands except per share data)
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Three months ended September 30,
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Nine months ended September 30,
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2013
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2012
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2013
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2012
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Income taxes:
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Current (provision for)
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-- | -- | -- | (104 | ) | |||||||||||
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Deferred benefit from
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-- | 1,285 | -- | 1,398 | ||||||||||||
| -- | 1,285 | -- | 1,294 | |||||||||||||
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Loss from continuing operations
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(706 | ) | (1,870 | ) | (6,469 | ) | (2,070 | ) | ||||||||
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Discontinued operations:
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Discontinued operations, net of taxes
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(8 | ) | (75 | ) | 430 | 15 | ||||||||||
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Loss on sale of discontinued
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operations, net of taxes
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(120 | ) | -- | (120 | ) | -- | ||||||||||
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Impairment on discontinued
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operations, net of taxes
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-- | -- | -- | (1,261 | ) | |||||||||||
| (128 | ) | (75 | ) | 310 | (1,246 | ) | ||||||||||
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Net loss
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$ | (834 | ) | $ | (1,945 | ) | $ | (6,159 | ) | $ | (3,316 | ) | ||||
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Net income (loss) per share basic and diluted
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Loss from continuing operations
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$ | (0.03 | ) | $ | (0.07 | ) | $ | (0.23 | ) | $ | (0.08 | ) | ||||
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Income (loss) from discontinued operations
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-- | -- | 0.01 | (0.04 | ) | |||||||||||
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Net (loss) per share
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$ | (0.03 | ) | $ | (0.07 | ) | $ | (0.22 | ) | $ | (0.12 | ) | ||||
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Weighted average shares outstanding
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Basic and Diluted
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27,682,602 | 27,468,355 | 27,677,382 | 27,458,249 | ||||||||||||
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U.S. ENERGY CORP.
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CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE
INCOME (LOSS)
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(Unaudited)
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(In thousands)
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Three months ended September 30,
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Nine months ended September 30,
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2013
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2012
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2013
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2012
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Net (loss)
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$ | (834 | ) | $ | (1,945 | ) | $ | (6,159 | ) | $ | (3,316 | ) | ||||
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Other comprehensive (loss) income:
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Marketable securities, net of tax
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(8 | ) | (60 | ) | (108 | ) | 3 | |||||||||
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Total comprehensive (loss)
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$ | (842 | ) | $ | (2,005 | ) | $ | (6,267 | ) | $ | (3,313 | ) | ||||
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U.S. ENERGY CORP.
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(Unaudited)
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(In thousands)
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For the nine months ended September 30,
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2013
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2012
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Cash flows from operating activities:
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Net loss
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$ | (6,159 | ) | $ | (3,316 | ) | ||
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Loss (gain) from discontinued operations
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(310 | ) | 1,246 | |||||
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(Loss) from continuing operations
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(6,469 | ) | (2,070 | ) | ||||
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Adjustments to reconcile net loss to
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net cash provided by operations
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Depreciation, depletion & amortization
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10,086 | 11,542 | ||||||
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Change in fair value of commodity price
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risk management activities, net
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1,056 | (1,233 | ) | |||||
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Impairment of oil and gas properties
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5,828 | 523 | ||||||
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Impairment of corporate aircraft
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-- | 1,756 | ||||||
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(Gain) on sale of marketable securities
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-- | (82 | ) | |||||
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Equity loss from Standard Steam
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40 | 168 | ||||||
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Net change in deferred income taxes
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-- | (1,196 | ) | |||||
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(Gain) loss on sale of assets
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(729 | ) | 11 | |||||
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Noncash compensation
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352 | 412 | ||||||
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Noncash services
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48 | 53 | ||||||
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Net changes in assets and liabilities
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160 | 702 | ||||||
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Net cash provided by operating activities
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10,372 | 10,586 | ||||||
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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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(12,614 | ) | (37,685 | ) | ||||
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Acquisition of property and equipment
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-- | (101 | ) | |||||
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Proceeds from sale of assets held for sale
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14,655 | -- | ||||||
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Proceeds from sale of oil and gas properties
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-- | 21,475 | ||||||
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Proceeds from sale of marketable securities
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-- | 101 | ||||||
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Proceeds from sale of property and equipment
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2,596 | 76 | ||||||
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Net change in restricted investments
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6 | (99 | ) | |||||
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Net cash provided by (used in) investing activities:
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4,643 | (16,233 | ) | |||||
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U.S. ENERGY CORP.
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
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(Unaudited)
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(In thousands)
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For the nine months ended September 30,
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2013
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2012
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Cash flows from financing activities:
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Issuance of common stock
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-- | 50 | ||||||
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Proceeds from new debt
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-- | 8,000 | ||||||
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Repayments of debt
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(12,621 | ) | (12,203 | ) | ||||
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Net cash (used in) financing activities
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(12,621 | ) | (4,153 | ) | ||||
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Net cash provided by operating activities
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of discontinued operations
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319 | 649 | ||||||
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Net increase (decrease) in cash and cash equivalents
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2,713 | (9,151 | ) | |||||
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Cash and cash equivalents at beginning of period
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2,825 | 12,874 | ||||||
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Cash and cash equivalents at end of period
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$ | 5,538 | $ | 3,723 | ||||
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Supplemental disclosures:
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Interest paid
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$ | 221 | $ | 110 | ||||
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Non-cash investing and financing activities:
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Unrealized gain from available for sale securities
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$ | 7 | $ | 81 | ||||
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Acquisition and development of oil and gas
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properties through accounts payable
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$ | 1,910 | $ | 4,679 | ||||
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Acquisition and development of oil and gas properties
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through asset retirement obligations
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$ | 61 | $ | 133 | ||||
The accompanying notes are an integral part of these statements.
-10-
1)
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements for the periods ended September 30, 2013 and September 30, 2012 have been prepared by U.S. Energy Corp. (“we,” “us,” “U.S. Energy” or the “Company”) in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The financial statements at September 30, 2013 include the Company’s wholly owned subsidiary Energy One LLC (“Energy One”), which owns the majority of the Company’s oil and gas assets. The Condensed Consolidated Balance Sheet at December 31, 2012 was derived from audited financial statements. In the opinion of the Company, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the financial position of the Company for the reported periods. Entities in which the Company holds at least 20% ownership or in which there are other indicators of significant influence are accounted for 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 U.S. GAAP have been condensed or omitted and certain prior period amounts have been reclassified to conform to the current period presentation. The unaudited condensed consolidated financial statements should be read in conjunction with the Company's December 31, 2012 Annual Report on Form 10-K (the “2012 10-K”). Subsequent events have been evaluated for financial reporting purposes through the date of the filing of this Form 10-Q.
2) Summary of Significant Accounting Policies
We follow accounting standards set by the Financial Accounting Standards Board, commonly referred to as the “FASB.” The FASB sets generally accepted accounting principles (U.S. GAAP) that we follow to ensure we consistently report our financial condition, results of operations, and cash flows.
For detailed descriptions of our significant accounting policies, please see the 2012 10-K (Note B pages 92 to 100).
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves used for depletion and impairment considerations 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.
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.
-11-
Components of Property and Equipment as of September 30, 2013 and December 31, 2012 are as follows:
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(In thousands)
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September 30,
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December 31,
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2013
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2012
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Oil & Gas properties
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Unproved
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$ | 9,687 | $ | 9,169 | ||||
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Wells in progress
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777 | -- | ||||||
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Proved
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127,382 | 119,919 | ||||||
| 137,846 | 129,088 | |||||||
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Less accumulated depreciation
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depletion and amortization
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(53,333 | ) | (43,454 | ) | ||||
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Net book value
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84,513 | 85,634 | ||||||
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Mineral properties
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20,739 | 20,739 | ||||||
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Building, land and equipment
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8,410 | 8,469 | ||||||
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Less accumulated depreciation
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(4,184 | ) | (4,034 | ) | ||||
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Net book value
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4,226 | 4,435 | ||||||
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Totals
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$ | 109,478 | $ | 110,808 | ||||
Oil and Gas Properties
The Company follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from property disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unproved properties.
Full Cost Pool
- Full cost pool capitalized costs are amortized over the life of production of proven properties. Capitalized costs at September 30, 2013 and December 31, 2012 which were not included in the amortized cost pool were $10.5 million and $9.2 million, respectively. These costs consist of exploratory wells in progress, seismic costs that are being analyzed for potential drilling locations as well as land costs related to unevaluated properties. No capitalized costs related to unevaluated properties are included in the amortization base at September 30, 2013 and December 31, 2012. 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.
-12-
Ceiling Test Analysis
- Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated average prices per barrel of oil and per MMbtu of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period and costs, adjusted for contract provisions and financial derivatives that hedge our oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by (iv) the income tax effects related to differences between the book and tax basis of the crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.
We perform a quarterly ceiling test for each of our oil and gas cost centers. There is only one such cost center in 2013. The reserves used in the ceiling test and the ceiling test itself incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In arriving at the ceiling test for the quarter ended September 30, 2013, we used $95.04 per barrel for oil and $3.612 per MMbtu for natural gas (and adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of our producing properties. The discount factor used was 10%.
During the three and nine months ended September 30, 2013, the Company recorded a proved property impairment of $0 and $5.8 million, respectively, related to its oil and gas assets. The impairment recorded for the nine months ended September 30, 2013 was primarily due to a decline in the price of oil, additional capitalized well costs and changes in production. During the nine months ended September 30, 2012, the Company recorded a proved property impairment of $523,000, primarily due to a decline in natural gas prices. Management will continue to review our unproved properties based on market conditions and other changes and, if appropriate, unproved property amounts may be reclassified to the amortized base of properties within the full cost pool.
Wells in Progress -
Wells in progress represent the costs associated with unproved wells that have not reached total depth or have not been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation. The costs for these wells are then transferred to evaluated property when the wells reach total depth and are completed and the costs become subject to depletion and the ceiling test calculation in future periods.
Mineral Properties
We capitalize all costs incidental to the acquisition of mineral properties. Mineral exploration costs are expensed as incurred. When exploration work indicates that a mineral property can be economically developed as a result of establishing proved and probable reserves, costs for the development of the mineral property as well as capital purchases and capital construction are capitalized and amortized using units of production over the estimated recoverable proved and probable reserves. Costs and expenses related to general corporate overhead are expensed as incurred. All capitalized costs are charged to operations if we subsequently determine that the property is not economical due to permanent decreases in market prices of commodities, excessive production costs or depletion of the mineral resource. Mineral properties at September 30, 2013 and December 31, 2012 reflect capitalized costs associated with our Mt. Emmons molybdenum property near Crested Butte, Colorado.
-13-
Our carrying balance in the Mt. Emmons property at September 30, 2013 and December 31, 2012 is as follows:
|
(In thousands)
|
||||||||
|
September 30,
|
December 31,
|
|||||||
|
2013
|
2012
|
|||||||
|
Costs associated with Mount Emmons
|
||||||||
|
beginning of year
|
$ | 20,739 | $ | 20,739 | ||||
|
Development costs
|
-- | -- | ||||||
|
Costs at the end of the period
|
$ | 20,739 | $ | 20,739 | ||||
Derivative Instruments
The Company uses derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying its oil and gas production. All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as cash flow hedges, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with forecasted future oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and classifies them as gain (loss) on derivative instruments, net in our consolidated statements of operations. The Company may also use puts, calls and basis swaps in the future.
The Company’s Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the Chief Executive Officer or President. The agreements with approved counterparties identify the Chief Executive Officer and President as the only Company representatives authorized to execute trades. See Note 5, Commodity Price Risk Management, for further discussion.
Revenue Recognition
The Company records oil and natural gas revenue under the sales method of accounting. Under the sales method, we recognize revenues based on the amount of oil or natural gas sold to purchasers, which may differ from the amounts to which we are entitled based on our interest in the properties. Natural gas balancing obligations as of September 30, 2013 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.
-14-
Recent Accounting Pronouncements
On January 1, 2013, the Company adopted new authoritative accounting guidance issued by the Financial Accounting Standards Board (“FASB”), which enhanced disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position and provided clarification as to the specific instruments that should be considered in these disclosures. These pronouncements were issued to facilitate comparison between financial statements prepared on the basis of GAAP and International Financial Reporting Standards. These disclosures are effective for annual and interim reporting periods beginning on or after January 1, 2013, and are to be applied retrospectively for all comparative periods presented. The impact of retrospectively adopting these pronouncements did not have a material impact on the Company’s consolidated financial statements but did impact the Company's disclosures.
In July 2013, the FASB issued new authoritative accounting guidance related to the reporting of unrecognized tax benefits when a net operating loss carryforward, similar tax loss, or tax credit carryforward exists. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2013. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures, but does not believe its financial statements will be significantly impacted.
The Company has reviewed other current outstanding statements from the FASB and does not believe that any of those statements will have a material adverse effect on the financial statements of the Company when adopted.
3) Assets Held for Sale
The Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 presented approximately $17.1 million in book value of assets held for sale, consisting of $15.2 million related to Remington Village and $1.9 million related to the corporate aircraft and related facilities. These assets were sold during the nine months ended September 30, 2013.
Remington Village Sale
On September 11, 2013, the Company, through its wholly owned subsidiary Remington Village LLC, completed the sale of the Remington Village Apartment Complex in Gillette Wyoming (“Remington Village”) to an affiliate of the Miller Frishman Group, LLC for $15.0 million. The $9.5 million balance on the commercial note relating to Remington Village was paid in full at closing. After deduction of payment of the note, commission and other closing costs, the net proceeds to the Company were approximately $5.0 million. Upon closing this transaction, the assets and liabilities held for sale were reduced to $0 and we recorded a loss on the sale of discontinued of operations of $120,000.
Because Remington Village has been classified as an asset held for sale, scheduled depreciation of $660,000 for the first nine months of 2013 and $560,000 for the first nine months of 2012 was not recorded.
-15-
Corporate Aircraft and Related Facilities Sale
On January 10, 2013, the Company sold the corporate aircraft for $1.9 million and the related facilities for $767,000.
4) Asset Retirement Obligations
We record the fair value of the reclamation liability for our inactive mining properties and our operating oil and gas properties as of the date that the liability is incurred. We review the liability each quarter and determine if a change in estimate is required, and we accrete the discounted liability on a quarterly basis for the future liability. Final determinations are made during the fourth quarter of each year. We deduct any actual funds expended for reclamation during the quarter in which it occurs.
The following is a reconciliation of the total liability for asset retirement obligations:
|
(In thousands)
|
||||||||
|
September 30,
|
December 31,
|
|||||||
|
2013
|
2012
|
|||||||
|
Beginning asset retirement obligation
|
$ | 686 | $ | 510 | ||||
|
Accretion of discount
|
28 | 34 | ||||||
|
Liabilities incurred
|
61 | 142 | ||||||
|
Ending asset retirement obligation
|
$ | 775 | $ | 686 | ||||
|
Mineral properties
|
$ | 171 | $ | 162 | ||||
|
Oil & Gas wells
|
604 | 524 | ||||||
|
Ending asset retirement obligation
|
$ | 775 | $ | 686 | ||||
|
|
||||||||
5) Commodity Price Risk Management
Through our wholly-owned subsidiary Energy One, we have entered into commodity derivative contracts (“economic hedges”) with BNP Paribas (“BNP”) and Wells Fargo, as described below. The derivative contracts are priced using West Texas Intermediate (“WTI”) quoted prices. The Company is a guarantor of Energy One’s obligations under the economic hedges. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of our future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions. The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features.
-16-
Energy One's commodity derivative contracts as of September 30, 2013 are summarized below:
|
Quantity
|
|||||||||||||
|
Settlement Period
|
Counterparty
|
Basis
|
(Bbls/day)
|
Strike Price
|
|||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
10/01/12 - 09/30/13
|
BNP Paribas
|
WTI
|
200 |
Put:
|
$ | 95.00 | |||||||
|
Call:
|
$ | 116.60 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
07/01/13 - 09/30/13
|
Wells Fargo
|
WTI
|
400 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.50 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
10/01/13 - 12/31/13
|
Wells Fargo
|
WTI
|
600 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.50 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 95.00 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.25 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
07/01/14 - 12/31/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 98.40 | |||||||||||
-17-
The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:
|
As of September 30, 2013
|
||||||||||
|
(in thousands)
|
||||||||||
|
Derivative Assets
|
Derivative Liabilities
|
|||||||||
|
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
|
Classification
|
Value
|
Classification
|
Value
|
|||||||
|
Crude oil costless collars
|
Current Asset
|
$ | 62 |
Current Liability
|
$ | 647 | ||||
Unrealized gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the condensed consolidated statement of income.
6) Fair Value Measurements
We follow authoritative guidance regarding fair value measurements for all assets and liabilities measured at fair value. That guidance establishes a fair value hierarchy that prioritizes the inputs the Company uses to measure fair value based on the significance level of the following inputs:
|
·
|
Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
|
·
|
Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and model-derived valuations whose inputs or significant value drivers are observable.
|
|
·
|
Level 3 - Significant inputs to the valuation model are unobservable.
|
Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. As of September 30, 2013, we held $75,000 of investments in marketable securities. We determine our estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, and quotes from third parties.
-18-
The following table is a listing of the Company’s assets and liabilities that are measured at fair value and their classification within the fair value hierarchy as of September 30, 2013:
|
(In thousands)
|
||||||||||||||||
|
Fair Value Measurements at September 30, 2013 Using
|
||||||||||||||||
|
September 30,
|
Quoted Prices in Active Markets for Identical Assets
|
Significant Other Observable Inputs
|
Significant Unobservable Inputs
|
|||||||||||||
|
Description
|
2013
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
||||||||||||
|
Commodity risk management assets
|
$ | 62 | $ | -- | $ | 62 | $ | -- | ||||||||
|
Available for sale securities
|
75 | 75 | -- | -- | ||||||||||||
|
Total assets
|
$ | 137 | $ | 75 | $ | 62 | $ | -- | ||||||||
|
Commodity risk management liability
|
$ | 647 | $ | -- | $ | 647 | $ | -- | ||||||||
|
Other accrued liabilities
1
|
746 | -- | -- | 746 | ||||||||||||
|
Total liabilities
|
$ | 1,393 | $ | -- | $ | 647 | $ | 746 | ||||||||
1
Other accrued liabilities is the company’s liability for the executive retirement program
Our other financial instruments include cash and cash equivalents, accounts receivable, accounts payable, other current liabilities and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and other current liabilities approximate fair value because of their immediate or short-term maturities. The carrying value of our debt approximates its fair market value since interest rates have remained generally unchanged from the issuance of the debt. The fair value and carrying value of our debt was $7.2 million as of September 30, 2013.
At September 30, 2013, total debt in the amount of $7.2 million consists of $7.0 million in debt from our reserve based senior credit facility and $200,000 in debt related to the purchase of land near our Mt. Emmons molybdenum property.
Revolving Credit Facility
On July 23, 2013, we entered into a second amendment (the "Second Amendment") to the senior secured revolving credit facility, dated July 30, 2010, as amended (the "Senior Credit Agreement"), among Energy One LLC, the Company, as guarantor party thereto, the lender parties thereto and Wells Fargo Bank, National Association. The Second Amendment provides for, among other things: (i) an extension of the maturity date of borrowings under the Senior Credit Agreement to July 30, 2017; (ii) a decrease in the applicable margin rate to between 2.00% and 3.00% for Eurdollar Loans and to between 1.00% and 2.00% for Alternate Base Rate Loans; (iii) a revision to the hedging covenant to permit the Company to hedge, for calendar year 2014 only, the greater of 600 barrels per day or 85% of the reasonably anticipated projected production, provided that in no event will any such hedge volumes for any calendar month during calendar year 2014 exceed actual production from the immediately preceding calendar month; and (iv) a $25 million borrowing base, subject to further adjustment from time to time in accordance with the Senior Credit Agreement.
-19-
The foregoing description of the Second Amendment is a summary only and is qualified in its entirety by reference to the Second Amendment, which was filed as Exhibit 10.1 to the Form 8-K filed on July 25, 2013.
As of September 30, 2013, we have borrowed $7.0 million under the Senior Credit Agreement to fund our oil and gas programs. Each borrowing under the agreement has a term of six months, but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility. Our intent is to extend this debt and therefore we have classified it as a long-term liability. The current weighted average interest rate on this debt is 2.44%. As of September 30, 2013, Energy One was in compliance with all the covenants under the Senior Credit Agreement.
Land Debt
The land debt of $200,000 bears an interest rate of 6.0% per annum and is due on January 2, 2014.
8) Shareholders’ Equity
Common Stock
During the three and nine months ended September 30, 2013, the Company issued 0 shares and 30,000 shares, respectively, of common stock to officers of the Company pursuant to the 2001 Stock Compensation Plan.
The following table details the changes in common stock during the nine months ended September 30, 2013:
|
(Amounts in thousands, except for share amounts)
|
||||||||||||
|
Additional
|
||||||||||||
|
Common Stock
|
Paid-In
|
|||||||||||
|
Shares
|
Amount
|
Capital
|
||||||||||
|
Balance January 1, 2013
|
27,652,602 | $ | 277 | $ | 123,078 | |||||||
|
2001 stock compensation plan
|
30,000 | -- | 48 | |||||||||
|
Expense of employee options vesting
|
-- | -- | 76 | |||||||||
|
Expense of outside director options vesting
|
-- | -- | 47 | |||||||||
|
Balance September 30, 2013
|
27,682,602 | $ | 277 | $ | 123,249 | |||||||
-20-
Stock Option Plans
The following table represents the activity in employee stock options and non-employee director stock options for the nine months ended September 30, 2013:
|
September 30, 2013
|
||||||||||||||||
|
Employee Stock Options
|
Director Stock Options
|
|||||||||||||||
|
Weighted
|
Weighted
|
|||||||||||||||
|
Average
|
Average
|
|||||||||||||||
|
Exercise
|
Exercise
|
|||||||||||||||
|
Options
|
Price
|
Options
|
Price
|
|||||||||||||
|
Outstanding balance at December 31, 2012
|
2,259,282 | $ | 3.80 | 150,000 | $ | 3.05 | ||||||||||
|
Granted
|
270,000 | $ | 2.08 | 36,000 | $ | 2.08 | ||||||||||
|
Forfeited
|
-- | $ | -- | -- | $ | -- | ||||||||||
|
Expired
|
(28,333 | ) | $ | 4.68 | (40,000 | ) | $ | 2.60 | ||||||||
|
Exercised
|
-- | $ | -- | -- | $ | -- | ||||||||||
|
Outstanding at September 30, 2013
|
2,500,949 | $ | 3.60 | 146,000 | $ | 2.93 | ||||||||||
|
Exercisable at September 30, 2013
|
2,137,619 | $ | 3.85 | 56,668 | $ | 3.46 | ||||||||||
|
Weighted Average Remaining Contractual Life - Years
|
4.26 | 8.35 | ||||||||||||||
|
Aggregate intrinsic value of options outstanding
|
$ | -- | $ | -- | ||||||||||||
Employee Stock Option Plans.
During the three and nine months ended September 30, 2013, we issued 270,000 options to employees under the U.S. Energy Corp. 2012 Equity and Performance Incentive Plan. The options were issued at the closing price of $2.08 on the date of grant, vest over a three year period and expire ten years from the date of grant. These options were valued under the Black-Scholes pricing model using a risk free interest rate of 1.66%, expected life of six years and expected volatility of 62.5879%. During the three and nine months ended September 30, 2013 we recorded $44,000 and $76,000, respectively, in compensation expense for employee stock options. During the three and nine months ended September 30, 2012 we recorded $15,000 and $17,000, respectively, in compensation expense for employee stock options. We will recognize an additional $414,000 in expense over the weighted average vesting period of 2.48 years related to the outstanding employee options.
Director Option Plans.
During the three and nine months ended September 30, 2013, we issued 36,000 options to non-employee directors under the 2008 Stock Option Plan for Independent Directors. The options were issued at the closing price of $2.08 on the date of grant, vest over a three year period and expire ten years from the date of grant. These options were valued under the Black-Scholes pricing model using a risk free interest rate of 1.66%, expected life of six years and expected volatility of 62.5879%. During the three and nine months ended September 30, 2013, we recorded $16,000 and $47,000, respectively, in expense for options issued to non-employee directors. During the three and nine months ended September 30, 2012, we recorded $16,000 and $53,000, respectively, in expense for options issued to non-employee directors. We will recognize an additional $107,000 in expense over the weighted average vesting period of 1.89 years related to the outstanding director options.
-21-
9) 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.
The deferred income tax assets or liabilities for an oil and gas exploration company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the asset or liability is subject to continual recalculation, 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 Company does not expect to pay any federal or state income tax for 2013 as a result of net operating loss carry forwards from prior years. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2013, the Company maintains a full valuation allowance on its net deferred tax assets. Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at the end of the reporting period.
-22-
10) Segment Information
As of September 30, 2013, we had two reportable segments: Oil and Gas and Maintenance of Mineral Properties. A summary of results of operations for the three and nine months ended September 30, 2013, and 2012, and total assets as of September 30, 2013 and December 31, 2012 by segment are as follows:
|
(In thousands)
|
(In thousands)
|
|||||||||||||||
|
For the three months ended September 30,
|
For the nine months ended September 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil and gas
|
$ | 8,582 | $ | 7,639 | $ | 24,376 | $ | 24,496 | ||||||||
|
Total revenues
|
8,582 | 7,639 | 24,376 | 24,496 | ||||||||||||
|
Operating expenses:
|
||||||||||||||||
|
Oil and gas
|
6,082 | 5,924 | 23,948 | 19,569 | ||||||||||||
|
Mineral properties
|
804 | 1,009 | 2,148 | 2,270 | ||||||||||||
|
Total operating expenses
|
6,886 | 6,933 | 26,096 | 21,839 | ||||||||||||
|
Interest expense:
|
||||||||||||||||
|
Oil and gas
|
65 | 45 | 213 | 103 | ||||||||||||
|
Mineral properties
|
3 | 6 | 9 | 18 | ||||||||||||
|
Total interest expense
|
68 | 51 | 222 | 121 | ||||||||||||
|
Operating income (loss)
|
||||||||||||||||
|
Oil and gas
|
$ | 2,435 | $ | 1,670 | $ | 215 | $ | 4,824 | ||||||||
|
Mineral properties
|
(807 | ) | (1,015 | ) | (2,157 | ) | (2,288 | ) | ||||||||
|
Operating income (loss)
|
||||||||||||||||
|
from identified segments
|
1,628 | 655 | (1,942 | ) | 2,536 | |||||||||||
|
General and administrative expenses
|
(1,337 | ) | (3,415 | ) | (3,963 | ) | (7,069 | ) | ||||||||
|
Add back interest expense
|
68 | 51 | 222 | 121 | ||||||||||||
|
Other revenues and expenses
|
(1,065 | ) | (446 | ) | (786 | ) | 1,048 | |||||||||
|
Income (loss) before income taxes
|
||||||||||||||||
|
and discontinued operations
|
$ | (706 | ) | $ | (3,155 | ) | $ | (6,469 | ) | $ | (3,364 | ) | ||||
|
Depreciation depletion and amortization expense:
|
||||||||||||||||
|
Oil and gas
|
$ | 3,205 | $ | 3,410 | $ | 9,879 | $ | 11,081 | ||||||||
|
Mineral properties
|
31 | 31 | 95 | 95 | ||||||||||||
|
Corporate
|
36 | 121 | 112 | 366 | ||||||||||||
|
Total depreciation expense
|
$ | 3,272 | $ | 3,562 | $ | 10,086 | $ | 11,542 | ||||||||
-23-
|
(In thousands)
|
||||||||
|
September 30
|
December 31,
|
|||||||
|
2013
|
2012
|
|||||||
|
Assets by segment
|
||||||||
|
Oil and gas
|
$ | 93,710 | $ | 93,839 | ||||
|
Mineral
|
20,746 | 20,747 | ||||||
|
Corporate
|
10,900 | 26,241 | ||||||
|
Total assets
|
$ | 125,356 | $ | 140,827 | ||||
11) Equity Income in Unconsolidated Investment
We recorded an equity gain from our unconsolidated investment in Standard Steam, LLC (“SST”) during the three months ended September 30, 2013, of $11,000 and an equity loss during the nine months ended September 30, 2013 of $40,000. During the three and nine months ended September 30, 2012, we recorded equity losses from our unconsolidated investment in SST of $17,000 and $168,000, respectively.
The following is Management's Discussion and Analysis of significant factors that have affected liquidity, capital resources and results of operations during the three and nine months ended September 30, 2013 and 2012. The following also updates information as to our financial condition provided in our 2012 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty (see “Forward Looking Statements”). The following discussion should also be read in conjunction with our condensed consolidated financial statements and the notes thereto.
General Overview
We are an independent energy company focused on the acquisition and development of oil and gas producing properties in the continental United States. Our business is currently focused in the Rocky Mountain region (specifically the Williston Basin of North Dakota and Montana), Texas and Louisiana, however, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.
We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our operations to other geographic areas. As a non-operator, we rely on our operating partners to propose, permit and manage wells. Before a well is drilled, the operator is required to provide all oil and gas interest owners in the designated well the opportunity to participate in the drilling costs and revenues of the well on a pro-rata basis. After the well is completed, our operating partners also transport, market and account for all production.
We are also involved in the exploration for and development of minerals (molybdenum) through our ownership of the Mt. Emmons molybdenum project in Colorado. Our carrying capitalized dollar amounts in each of these areas at September 30, 2013 and December 31, 2012 were as follows:
|
(In thousands)
|
||||||||
|
September 30,
|
December 31,
|
|||||||
|
2013
|
2012
|
|||||||
|
Unproved oil and gas properties
|
$ | 10,464 | $ | 9,169 | ||||
|
Proved oil and gas properties
|
74,049 | 76,465 | ||||||
|
Undeveloped mining properties
|
20,739 | 20,739 | ||||||
| $ | 105,252 | $ | 106,373 | |||||
Oil and Gas Activities
We have active agreements with several oil and gas exploration and production companies. Our working interest varies by project (and may vary over time depending on the terms of the relevant agreement), but typically ranges from approximately 1% to 62%. These projects may result in numerous wells being drilled over the next three to five years. We are also actively pursuing the potential acquisition of additional exploration, development or production stage oil and gas properties or companies. The following table details our interests in producing wells as of September 30, 2013 and 2012.
|
September 30,
|
|||||||
|
2013
|
2012
|
||||||
|
Gross
|
Net
(1)
|
Gross
|
Net
(1)
|
||||
|
Williston Basin:
|
|||||||
|
Productive wells
|
82.00
|
10.10
|
62.00
|
10.44
|
|||
|
Wells being drilled or awaiting completion
|
9.00
|
0.18
|
4.00
|
0.17
|
|||
|
Gulf Coast/South Texas:
|
|||||||
|
Productive wells
|
3.00
|
0.56
|
3.00
|
0.56
|
|||
|
Wells being drilled or awaiting completion
|
--
|
--
|
2.00
|
0.20
|
|||
|
Eagle Ford/Buda:
|
|||||||
|
Productive wells
|
5.00
|
1.50
|
3.00
|
0.90
|
|||
|
Wells being drilled or awaiting completion
|
2.00
|
0.45
|
--
|
--
|
|||
|
Austin Chalk:
|
|||||||
|
Productive wells
|
11.00
|
2.98
|
11.00
|
2.98
|
|||
|
Wells being drilled or awaiting completion
|
--
|
--
|
--
|
--
|
|||
|
Total:
|
|||||||
|
Productive wells
|
101.00
|
15.14
|
79.00
|
14.88
|
|||
|
Wells being drilled or awaiting completion
|
11.00
|
0.63
|
6.00
|
0.57
|
|||
|
(1)
|
Net working interests may vary over time under the terms of the applicable contracts.
|
Williston Basin, North Dakota
Rough Rider Prospect.
We participate in fifteen 1,280 acre drilling units in the Rough Rider prospect with Brigham Oil & Gas, L.P. (“Brigham”), a subsidiary of Statoil. From August 24, 2009 to September 30, 2013, we have drilled and completed 21 gross (6.23 net) Bakken formation wells and one gross (0.18 net) Three Forks formation well under the Drilling Participation Agreement with Brigham.
During the nine months ended September 30, 2013, we drilled and completed one gross well (0.04 net) with Brigham. One additional gross (0.06 net) well has been drilled and was awaiting completion. Our net investment in the Rough Rider prospect wells was $2.4 million for the nine months ended September 30, 2013. Two additional gross (0.05 net) wells are expected to be drilled in the fourth quarter of 2013. Brigham operates all of the wells.
Yellowstone and SEHR Prospects.
We participate in twenty-seven gross 1,280 acre spacing units in the Yellowstone and SEHR prospects with Zavanna, LLC (“Zavanna”). Through September 30, 2013, we have drilled and completed 24 gross (2.91 net) Bakken formation wells and 4 gross (0.29 net) Three Forks formation wells in these prospects. The wells are operated by Zavanna (18 gross, 2.97 net) Emerald Oil, Inc. (5 gross, 0.05 net), Murex Petroleum (2 gross, 0.13 net), Kodiak Oil & Gas Corp. (2 gross, 0.04 net) and Slawson Exploration Company, Inc. (1 gross, 0.01 net). At September 30, 2013, four additional gross (0.04 net) wells had been spud and were in progress.
During the first nine months of 2013, we completed eleven gross (0.49 net) wells in the Yellowstone and SEHR prospects. Our net investment in the Yellowstone and SEHR prospect wells was $4.8 million during the nine months ended September 30, 2013.
Bakken/Three Forks Asset Package
. Under the Bakken/Three Forks asset package we acquired in 2012, we participate in 23 drilling units in McKenzie, Williams and Mountrail Counties of North Dakota. At September 30, 2013, there were 32 gross (0.49 net) producing wells in these drilling units. All acreage is currently held by production and produces approximately 54 barrels of oil equivalent (“BOE”) per day net to the Company.
During the first nine months of 2013, we completed three gross (0.05 net) wells on this acreage and two additional gross (0.05 net) wells were drilled and awaiting completion. Our net investment in wells under the drilling units in this program was $1.0 million during the nine months ended September 30, 2013.
U.S. Gulf Coast (Onshore) / South Texas
We participate with three different operators in the U.S. Gulf Coast (onshore). At September 30, 2013, we had three gross producing (0.56 net) wells in this region. Our net investment in Gulf Coast / South Texas wells and properties was $52,000 during the nine months ended September 30, 2013.
Eagle Ford Shale and Buda Limestone
We participate in the Leona River and Booth-Tortuga Eagle Ford/Buda prospects with Contango Oil & Gas Company ("Contango") and in the Big Wells Buda prospect with U.S. Enercorp. During the nine months ended September 30, 2013, we drilled and completed the Beeler 2H and Beeler 3H Buda limestone wells (0.60 net combined) in the Booth-Tortuga prospect. Two additional Buda limestone wells (0.45 net combined) had been spud as of September 30, 2013. Our net investment in these wells, including lease acquisition costs in the prospects during the first nine months of 2013, was $6.2 million.
2013 Production Results
The following table provides a regional summary of our net production during the first nine months of 2013:
|
Williston Basin
|
Gulf Coast / South Texas
|
Eagle Ford /
Buda
|
Austin Chalk
|
Total
|
||||||||
|
First Nine Months of 2013 Production
|
||||||||||||
|
Oil (Bbl)
|
215,540
|
1,225
|
24,033
|
6,522
|
247,320
|
|||||||
|
Gas (Mcf)
|
104,974
|
144,180
|
28,317
|
2,948
|
280,419
|
|||||||
|
NGLs (Bbl)
|
6,526
|
107
|
519
|
478
|
7,630
|
|||||||
|
Equivalent (BOE)
|
239,562
|
25,362
|
29,272
|
7,490
|
301,686
|
|||||||
|
Avg. Daily Equivalent (BOE/d)
|
878
|
93
|
107
|
27
|
1,105
|
|||||||
|
Relative percentage
|
80%
|
8%
|
10%
|
2%
|
100%
|
|||||||
Mount Emmons Molybdenum Project
On April 22, 2013, we received a letter from the U.S. Forest Service (“USFS”) notifying the Company that the USFS has completed a review of the Mine Plan of Operations (“MPO” or the “Plan”) for the Mount Emmons Molybdenum Project in Colorado (the “Project”) and that it has determined that the MPO “does contain sufficient information and clarity to form the basis for a proposed action to initiate scoping and analysis under the National Environmental Policy Act (‘NEPA’).” The letter also states, “U.S. Energy has met the requirements of the Reality Check provision granting conditional water rights for the Mt. Emmons Molybdenum Project by filing the Plan for the Mt. Emmons Mine with the USFS. No other special use permits or rights-of-way for the water facilities are required because they are addressed in the Plan.” The MPO provides an in-depth description of the proposed construction, mining, processing, and reclamation operations for the Project. The Company has initiated scoping analysis of the MPO with the USFS and anticipates that such work will continue through the balance of 2013.
Additional Comparative Data
The following table provides information regarding selected production and financial information for the quarter ended September 30, 2013 and the immediately preceding three quarters.
|
For the Three Months Ended
|
||||||||||||||||
|
September 30,
2013
|
June 30,
2013
|
March 31,
2013
|
December 31,
2012
|
|||||||||||||
|
(in Thousands, except for production data)
|
||||||||||||||||
|
Production (BOE)
|
101,987 | 101,026 | 98,674 | 107,823 | ||||||||||||
|
Oil, gas and NGL production revenue
|
$ | 8,582 | $ | 7,915 | $ | 7,879 | $ | 8,039 | ||||||||
|
Unrealized and realized derivative gain (loss)
|
$ | (1,075 | ) | $ | 347 | $ | (602 | ) | $ | (5 | ) | |||||
|
Lease operating expense
|
$ | 2,006 | $ | 1,765 | $ | 1,966 | $ | 1,969 | ||||||||
|
Production taxes
|
$ | 871 | $ | 800 | $ | 833 | $ | 852 | ||||||||
|
DD&A
|
$ | 3,205 | $ | 3,213 | $ | 3,461 | $ | 3,812 | ||||||||
|
General and administrative
|
$ | 1,337 | $ | 1,319 | $ | 1,307 | $ | 1,497 | ||||||||
|
Mineral holding costs
|
$ | 410 | $ | 297 | $ | 227 | $ | 205 | ||||||||
|
Water treatment plant
|
$ | 394 | $ | 403 | $ | 417 | $ | 424 | ||||||||
|
Income (loss) from continuing operations
|
$ | (706 | ) | $ | 367 | $ | (6,130 | ) | $ | (5,932 | ) | |||||
Results of Operations
Three Months Ended September 30, 2013 compared to Three Months Ended September 30, 2012
During the three months ended September 30, 2013, we recorded a net loss after taxes of $834,000, or $0.03 per share basic and diluted as compared to a net loss after taxes of $1.9 million, or $0.07 per share basic and diluted during the same period of 2012. Significant components of the changes in results of operations for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 are as follows:
Oil and Gas Operations.
Oil and gas operations generated operating income of $2.5 million during the quarter ended September 30, 2013 as compared to operating income of $1.7 million during the quarter ended September 30, 2012. The following table summarizes production volumes, average sales prices and operating revenues for the three months ended September 30, 2013 and 2012:
|
Three Months Ended
|
||||||||||||
|
September 30,
|
Increase
|
|||||||||||
|
2013
|
2012
|
(Decrease)
|
||||||||||
|
Production volumes
|
||||||||||||
|
Oil (Bbls)
|
81,535 | 90,321 | (8,786 | ) | ||||||||
|
Natural gas (Mcf)
|
104,025 | 77,861 | 26,164 | |||||||||
|
Natural gas liquids (Bbls)
|
3,114 | 2,762 | 352 | |||||||||
|
Equivalent (BOE)
|
101,987 | 106,060 | (4,073 | ) | ||||||||
|
Avg. Daily Equivalent (BOE/d)
|
1,109 | 1,153 | (44 | ) | ||||||||
|
Average sales prices
|
||||||||||||
|
Oil (per Bbl)
|
$ | 98.12 | $ | 80.55 | $ | 17.57 | ||||||
|
Natural gas (per Mcf)
|
4.38 | 3.28 | 1.10 | |||||||||
|
Natural gas liquids (per Bbl)
|
40.40 | 39.46 | 0.94 | |||||||||
|
Equivalent (BOE)
|
84.15 | 72.03 | 12.12 | |||||||||
|
Operating revenues (in thousands)
|
||||||||||||
|
Oil
|
$ | 8,000 | $ | 7,275 | $ | 725 | ||||||
|
Natural gas
|
456 | 255 | 201 | |||||||||
|
Natural gas liquids
|
126 | 109 | 17 | |||||||||
|
Total operating revenue
|
8,582 | 7,639 | 943 | |||||||||
|
Lease operating expense
|
(2,006 | ) | (1,692 | ) | (314 | ) | ||||||
|
Production taxes
|
(871 | ) | (822 | ) | (49 | ) | ||||||
|
Impairment
|
- | - | - | |||||||||
|
Income before depreciation, depletion and amortization
|
5,705 | 5,125 | 580 | |||||||||
|
Depreciation, depletion and amortization
|
(3,205 | ) | (3,410 | ) | 205 | |||||||
|
Income
|
$ | 2,500 | $ | 1,715 | $ | 785 | ||||||
During the three months ended September 30, 2013, we produced 101,987 BOE, or an average of 1,109 BOE/day. Portions of our natural gas production are sent to gas processing plants to extract from the gas various natural gas liquids (“NGLs”) that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs is classified as lease operating expenses.
We recognized $8.6 million in revenues during the three months ended September 30, 2013 as compared to $7.6 million during the same period of the prior year. The $943,000 increase in revenue is primarily due to higher realized oil and gas prices in 2013 when compared to the same period in 2012. Oil sales volumes were lower in the three months ended September 30, 2013 when compared to the same period in 2012, primarily due to production declines from wells in the Williston Basin and a 35% reduction of our working and net revenue interest upon payout in the first group of six wells drilled with Brigham.
Our average net realized price (operating revenue per BOE) for the three months ended September 30, 2013 was $84.15 per BOE compared with $72.03 for the same period in 2012. The increase in our equivalent realized price for production corresponds with higher average oil and natural gas prices in 2013 when compared with the same period in 2012. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $3.00 to $12.00 per barrel during the first nine months of 2013. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices.
Lease operating expense of $2.0 million for the three months ended September 30, 2013 was comprised of $1.9 million in lease operating expense and $154,000 in workover expense. The $314,000 increase in total lease operating expense in 2013 as compared to the same period in 2012 is primarily a result of an increase in net producing wells.
Our depletion, depreciation and amortization (DD&A) rate for the three months ended September 30, 2013 was $31.43 per BOE compared to $32.36 per BOE for the same period in 2012. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
During the balance of 2013 we anticipate completing wells that were drilled during the first three quarters of 2013 as well as drilling and completing new wells. We also anticipate that our production rates will remain relatively stable as a result of these activities. Various factors, including extensive workover costs on existing wells, lower commodity prices, commodity price differentials, cost overruns on projected drilling projects, unsuccessful wells or other development activities and/or faster than expected declines in production from existing wells, would have a negative effect on production, cash flows and earnings from the oil and gas segment and could cause actual results to differ materially from those we expect.
Mt. Emmons and Water Treatment Plant Operations.
We recorded $394,000 in costs and expenses for the water treatment plant and $410,000 for holding costs for the Mt. Emmons molybdenum property during the three months ended September 30, 2013. During the three months ended September 30, 2012, we recorded $609,000 in operating costs related to the water treatment plant and $400,000 in holding costs.
General and Administrative
. General and administrative expenses decreased by $322,000 during the three months ended September 30, 2013 as compared to general and administrative expenses for the three months ended September 30, 2012. Lower general and administrative costs in 2013 are primarily a result of reductions of $100,000 in contract services, $84,000 in depreciation expense, $65,000 in professional services, $51,000 in compensation expense and $21,000 in travel costs.
Other income and expenses.
We recognized an unrealized and realized derivative loss of $1.1 million in the third quarter of 2013 compared to a loss of $466,000 for the same period in 2012. The 2013 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $768,000 and realized cash settlement losses on derivatives of $307,000.
Gain on the sale of assets increased to $19,000 during the quarter ended September 30, 2013 compared to a loss of $21,000 during the quarter ended September 30, 2012. We recorded an equity gain of $11,000 and an equity loss of $17,000 from the investment in Standard Steam Trust LLC (“SST”) during the quarters ended September 30, 2013 and 2012, respectively. Equity losses from the investment in SST are expected to occur until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.
Gain on the sale of marketable securities (shares of Sutter Gold Mining) decreased to $0 during the quarter ended September 30, 2013 from $28,000 during the quarter ended September 30, 2012.
Interest income was $1,000 and $2,000 during the quarters ended September 30, 2013 and 2012, respectively.
As a result of higher average debt balances, interest expense increased to $71,000 during the quarter ended September 30, 2013 from $53,000 during the quarter ended September 30, 2012.
Discontinued operations.
We recorded losses of $128,000 and $75,000, net of taxes, from Remington Village during the quarters ended September 30, 2013 and September 30, 2012, respectively. Higher losses in the quarter ended September 30, 2013 as compared to the quarter ended September 30, 2012 primarily result from a $120,000 loss on the sale of discontinued operations recorded upon closing the sale of Remington Village in September 2013.
Nine Months Ended September 30, 2013 compared to Nine Months Ended September 30, 2012
During the nine months ended September 30, 2013, we recorded a net loss after taxes of $6.2 million, or $0.22 per share basic and diluted as compared to a net loss after taxes of $3.3 million, or $0.12 per share basic and diluted during the same period of 2012. Significant components of the changes in results of operations for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 are as follows:
Oil and Gas Operations.
Before impairment, oil and gas operations produced operating income of $6.3 million during the nine months ended September 30, 2013 as compared to operating income of $5.5 million during the nine months ended September 30, 2012. The following table summarizes production volumes, average sales prices and operating revenues for the nine months ended September 30, 2013 and 2012:
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
Increase
|
|||||||||||
|
2013
|
2012
|
(Decrease)
|
||||||||||
|
Production volumes
|
||||||||||||
|
Oil (Bbls)
|
247,320 | 282,733 | (35,413 | ) | ||||||||
|
Natural gas (Mcf)
|
280,419 | 262,932 | 17,487 | |||||||||
|
Natural gas liquids (Bbls)
|
7,630 | 10,325 | (2,695 | ) | ||||||||
|
Equivalent (BOE)
|
301,687 | 336,880 | (35,193 | ) | ||||||||
|
Avg. Daily Equivalent (BOE/d)
|
1,105 | 1,229 | (124 | ) | ||||||||
|
Average sales prices
|
||||||||||||
|
Oil (per Bbl)
|
$ | 92.20 | $ | 82.06 | $ | 10.14 | ||||||
|
Natural gas (per Mcf)
|
4.48 | 3.07 | 1.41 | |||||||||
|
Natural gas liquids (per Bbl)
|
41.81 | 47.46 | (5.65 | ) | ||||||||
|
Equivalent (BOE)
|
80.80 | 72.71 | 8.09 | |||||||||
|
Operating revenues (in thousands)
|
||||||||||||
|
Oil
|
$ | 22,802 | $ | 23,200 | $ | (398 | ) | |||||
|
Natural gas
|
1,255 | 806 | 449 | |||||||||
|
Natural gas liquids
|
319 | 490 | (171 | ) | ||||||||
|
Total operating revenue
|
24,376 | 24,496 | (120 | ) | ||||||||
|
Lease operating expense
|
(5,737 | ) | (5,332 | ) | (405 | ) | ||||||
|
Production taxes
|
(2,504 | ) | (2,633 | ) | 129 | |||||||
|
Impairment
|
(5,828 | ) | (523 | ) | (5,305 | ) | ||||||
|
Income before depreciation, depletion and amortization
|
10,307 | 16,008 | (5,701 | ) | ||||||||
|
Depreciation, depletion and amortization
|
(9,879 | ) | (11,081 | ) | 1,202 | |||||||
|
Income
|
$ | 428 | $ | 4,927 | $ | (4,499 | ) | |||||
During the nine months ended September 30, 2013, we produ
ced 301,687 BOE, or an average of 1,105 BOE/day. Portions of our natural gas production are sent to gas processing plants to extract from the gas various NGLs that are sold separately from the remaining natural gas. We sell some of our gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGLs and the remaining natural gas. In the table above, our share of processing costs is classified as lease operating expenses.
We recognized $24.4 million in revenues during the nine months ended September 30, 2013 as compared to $24.5 million during the same period of the prior year. The $120,000 decrease in revenue is primarily due to lower sales volumes in 2013 when compared to the same period in 2012, partially offset by higher average realized prices for oil and natural gas in 2013. Revenue from oil sales was lower in the nine months ended September 30, 2013 when compared to the same period in 2012, primarily due to production declines from wells in the Williston Basin and a 35% reduction of our working and net revenue interest upon payout in the first group of six wells drilled with Brigham.
Our average net realized price (operating revenue per BOE) for the nine months ended September 30, 2013 was $80.80 per BOE compared with $72.71 for the same period in 2012. The increase in our equivalent realized price for production corresponds with higher average oil and natural gas prices in 2013 when compared with the same period in 2012. Due to takeaway constraints, the discount, or differential, for oil prices in the Williston Basin has ranged from $3.00 to $12.00 per barrel during the first nine months of 2013. Until additional takeaway capacity is available, we expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices.
Lease operating expense of $5.7 million for the nine months ended September 30, 2013 was comprised of $5.0 million in lease operating expense and $731,000 in workover expense. The $405,000 increase in total lease operating expense in 2013 as compared to the same period in 2012 is primarily a result of an increase in net producing wells.
During the nine months ended September 30, 2013, the Company recorded a proved property impairment of $5.8 million related to its oil and gas assets. The impairment, which was recorded in the first quarter of 2013, was primarily due to a decline in the price of oil, additional capitalized costs and changes in production. During the nine months ended September 30, 2012, the Company recorded a proved property impairment of $523,000, primarily due to a decline in natural gas prices.
Our depletion, depreciation and amortization (DD&A) rate for the nine months ended September 30, 2013 was $32.75 per BOE compared to $32.89 per BOE for the same period in 2012. Our DD&A rate can fluctuate as a result of impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
During the balance of 2013 we anticipate completing wells that were drilled during the first three quarters of 2013 as well as drilling and completing new wells. We also anticipate that our production rates will remain relatively stable as a result of these activities. Various factors, including extensive workover costs on existing wells, lower commodity prices, commodity price differentials, cost overruns on projected drilling projects, unsuccessful wells or other development activities and/or faster than expected declines in production from existing wells, would have a negative effect on production, cash flows and earnings from the oil and gas segment and could cause actual results to differ materially from those we expect.
Mt. Emmons and Water Treatment Plant Operations.
We recorded $1.2 million in costs and expenses for the water treatment plant and $934,000 for holding costs for the Mt. Emmons molybdenum property during the nine months ended September 30, 2013. During the nine months ended September 30, 2012, we recorded $1.6 million in operating costs related to the water treatment plant and $716,000 in holding costs.
General and Administrative
. General and administrative expenses decreased by $1.4 million during the nine months ended September 30, 2013 as compared to general and administrative expenses for the nine months ended September 30, 2012. Lower general and administrative costs in 2013 are primarily a result of reductions of $448,000 in compensation expense, $311,000 in contract services, $250,000 in depreciation expense, $176,000 in professional services, $115,000 in other operating costs, $47,000 in bank charges and $32,000 in travel costs.
Other income and expenses.
We recognized an unrealized and realized derivative loss of $1.3 million in the first nine months of 2013 compared to a gain of $1.1 million for the same period in 2012. The 2013 amount includes a loss on unrealized changes in the fair value of our commodity derivative contracts of $1.1 million and realized cash settlement losses on derivatives of $274,000.
During the nine months ended September 30, 2013, we sold our corporate aircraft and related facilities and other miscellaneous equipment. As a result, we recorded a gain on the sale of assets during the period in the amount of $729,000. During the nine months ended September 30, 2012, we recorded a loss on the sale of assets of $11,000. We recorded equity losses of $40,000 and $168,000 from the investment in Standard Steam Trust LLC (“SST”) during the nine months ended September 30, 2013 and 2012, respectively. Equity losses from the investment in SST are expected to continue until such time as SST properties are sold, equity losses reduce our investment to zero or we sell the investment.
Gain on the sale of marketable securities (shares of Sutter Gold Mining) decreased to $0 during the nine months ended September 30, 2013 from $82,000 during the nine months ended September 30, 2012.
Interest income decreased to $4,000 during the nine months ended September 30, 2013 from $8,000 during the nine months ended September 30, 2012. The decrease is a result of lower amounts of cash invested in interest bearing instruments during the nine-month period ended September 30, 2013.
As a result of higher average debt balances, interest expense increased to $229,000 during the nine months ended September 30, 2013 from $128,000 during the nine months ended September 30, 2012.
Discontinued operations.
We recorded income of $310,000, net of taxes, from Remington Village during the nine months ended September 30, 2013 and loss of $1.3 million, net of taxes for the nine months ended September 30, 2012. The $1.0 million increase in income when comparing the nine months ended September 30, 2013 to the nine months ended September 30, 2012 is primarily a result of a $1.3 million non-cash impairment recorded during the nine months ended September 30, 2012 and is partially offset by a $120,000 loss on the sale of discontinued operations recorded upon closing the sale of Remington Village in September 2013.
Overview of Liquidity and Capital Resources
At September
30, 2013, we had $5.5 million in cash and cash equivalents. Our working capital (current assets minus current liabilities) was $5.1 million. As discussed below in Capital Resources and Capital Requirements, we project that our capital resources at September
30, 2013 will be sufficient to fund operations and capital projects through the balance of 2013. Given the size of our potential commitments related to our existing inventory of drilling projects, however, our requirements for additional capital could increase significantly during the remainder of 2013 if we make acquisitions or elect to participate in any currently unanticipated drilling of additional wells. As a result, we may consider drawing down additional debt on our senior credit facility, selling or joint venturing an interest in some of our oil and gas assets, or accessing the capital markets or other alternatives, as we determine how to best fund our capital program.
The principal recurring uncertainty which affects the Company is variable prices for commodities producible from our oil, gas and mineral properties. Significant price swings can have adverse or positive effects on our business of exploring for, developing and producing oil and gas or minerals. Availability of drilling and completion equipment and crews fluctuates with the market prices for oil and natural gas and thereby affects the cost of drilling and completing wells. When prices are low there is typically less exploration activity and the cost of drilling and completing wells is generally reduced. Conversely, when prices are high there is generally more exploration activity and the cost of drilling and completing wells generally increases.
Capital Resources
Primary potential sources of future liquidity include the following:
Oil and Gas Production.
At September 30, 2013, we had 101 gross (15.14 net) producing wells. During the nine months ended September 30, 2013, we received an average of $2.7 million per month from these producing wells with an average operating cost of $637,000 per month (including workover costs) and production taxes of $278,000, for average net cash flows of $1.8 million per month from oil and gas production before non-cash depletion expense. We anticipate that cash flows from oil and gas operations will remain stable and may increase through the balance of 2013 as additional wells being drilled with Contango, Brigham, and others begin to produce. However, decreases in the price of oil and natural gas, increased operating costs and workover expenses, declines in production rates, and other factors could reduce these average monthly cash flow amounts.
Normal production declines and the back-in after payout provisions granted to Brigham and Zavanna will eventually decrease the amount of cash flow we receive from these wells. We anticipate drilling more Buda limestone wells with Contango and U.S. Enercorp and additional Bakken and Three Forks wells with Brigham, Zavanna and others in the future and will continue to search for additional drilling opportunities to replace these oil reserves and cash flows.
Cash on Hand.
At September 30, 2013, we had $5.5 million in cash and cash equivalents.
Wells Fargo Senior Credit Facility.
On July 30, 2010, we established a senior credit facility through our wholly owned subsidiary, Energy One, LLC (“Energy One”) to borrow up to $75 million (since increased to $100 million as described below) from a syndicate of banks, financial institutions and other entities, including Wells Fargo Bank, National Association, which subsequently acquired the North American reserve-based and related diversified energy lending business of our initial lending institution, BNP Paribas. The senior credit facility is being used to advance our short and mid-terms goals of increasing our investment in oil and gas.
From time to time until the expiration of the credit facility (July 30, 2017), if Energy One is in compliance with the facility documents, Energy One may borrow, pay, and re-borrow funds from the lenders, up to an amount equal to the borrowing base. The borrowing base is redetermined semi-annually, taking into account updated reserve reports. Any proposed increase in the borrowing base will require approval by all lenders in the syndicate, and any proposed borrowing base decrease will require approval by lenders holding not less than two-thirds of outstanding loans and loan commitments. As of July 23, 2013, the commitment amount is $100 million and the borrowing base is $25 million based on the semi-annual redetermination using our December 31, 2012 financial statements, production reports and our March 31, 2013 reserve report. As of September 30, 2013, Energy One was in compliance with all the covenants under the senior credit facility.
As of September 30, 2013, we have borrowed $7.0 million under the senior credit facility.
Capital Requirements
Our direct capital requirements during the balance of 2013 relate to the funding of our drilling programs, the potential acquisition of prospective oil and gas properties and/or existing production, payment of debt obligations, operating and capital improvement costs relating to the water treatment plant at the Mt. Emmons project and ongoing permitting activities for the Mt. Emmons project and general and administrative costs. We intend to finance our 2013 capital expenditure plan primarily from the sources described above under “Capital Resources”. We may be required to reduce or defer part of our 2013 capital expenditures plan if we are unable to obtain sufficient financing from these sources. We regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements and other factors.
Oil and Gas Exploration and Development.
Through September 30, 2013, we have spent approximately $14.6 million of our $27.1 million 2013 oil and gas capital expenditure budget. The remaining $12.5 million is currently budgeted to be spent on exploration and acquisition initiatives in Texas and in the Williston Basin of North Dakota. Actual capital expenditures for each regional drilling program is contingent upon timing, well costs and success. If any of our drilling initiatives are not initially successful or progress more slowly than anticipated, funds allocated for that program may be allocated to other initiatives and/or acquisitions in due course. The actual number of gross and net wells could vary in each of these cases.
Mt. Emmons Molybdenum Project.
We are responsible for all costs associated with the Mt. Emmons project, which includes operation of a water treatment plant. Operating costs for the water treatment plant during the remainder of 2013 are expected to be approximately $141,000 per month. Additionally, we have a remaining budget of $263,000 for water treatment plant capital improvements that are expected to improve the plant’s efficiency and reduce costs and $630,000 for advancement of the Mine Plan of Operations. However, we do not expect that these full amounts will be spent prior to year-end.
In 2009, 160 acres of fee land in the vicinity of the mining claims was purchased by the Company and Thompson Creek Metals Company USA (“TCM”) for $4 million ($2 million in January 2009, $400,000 annually for five years thereafter). TCM has agreed in principle to sell its 50% interest in the property to the Company for $1.0 million and assumption of TCM’s final $200,000 note payment. Final documents have not been executed; however, we expect the transaction to close in the fourth quarter of 2013.
Insurance.
We have liability insurance coverage in amounts we deem sufficient and in line with industry standards for the location, stage, and type of operations in oil and gas and mineral property development (the Mt. Emmons molybdenum project). 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.
Reclamation Costs.
We have reclamation obligations with an estimated present value of $604,000 related to our oil and gas wells and $172,000 related to the Mt. Emmons molybdenum property. No reclamation is expected to be performed during the year ended December 31, 2013 unless a well, or wells, are abandoned due to unexpected operational challenges or if a well becomes uneconomical. As the Mt. Emmons project is developed, the reclamation liability is expected to increase. Our objective, upon closure of the proposed mine at the Mt. Emmons project, is to eliminate long-term liabilities associated with the property.
Cash Flows During the Nine Months Ended September 30, 2013
The following table presents changes in cash flows between the nine month periods ended September 30, 2013 and 2012. The analysis following the table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.
|
(In thousands)
|
||||||||||||
|
For the nine months ended September 30,
|
||||||||||||
|
2013
|
2012
|
Change
|
||||||||||
|
Net cash provided by operating activities
|
$ | 10,372 | $ | 10,586 | $ | (214 | ) | |||||
|
Net cash (used in) provided by investing activities
|
4,643 | (16,233 | ) | 20,876 | ||||||||
|
Net cash (used in) financing activities
|
(12,621 | ) | (4,153 | ) | (8,468 | ) | ||||||
Operating Activities
. Cash provided by operations for the nine month period ended September 30, 2013 decreased to $10.4 million as compared to cash provided by operations of $10.6 million for the same period of the prior year. This $214,000 year over year decrease in cash from operating activities is part of the complete discussion of cash provided by operations in “Results of Operations” above.
Investing Activities
. Investing activities provided cash during the first nine months of 2013 through $14.7 million in proceeds from the sale of Remington Village, $2.6 million in proceeds from the sale of property and equipment related to the Company’s aircraft and related facilities and $6,000 from a change in the value of restricted investments.
Investing activities consumed cash through the acquisition and development of oil and gas properties in the amount of $12.6 million during the first nine months of 2013.
The $20.9 million change in investing activities during the nine months ended September 30, 2013 as compared to the same period of the prior year is primarily a result of: (a) $21.5 million in sales of oil and gas properties during 2012 with no oil and gas property sales during the same period in 2013, (b) $14.7 million in proceeds from the sale of discontinued operations in 2013 with no discontinued operations sales in the 2012 period, (c) $2.6 million in proceeds from the sale of property and equipment in 2013 as compared to $76,000 during the nine months ended September 30, 2012 and (d) a $25.1 million reduction in investment in oil and gas properties in 2013 as compared to the same period in 2012.
Financing Activities
. Financing activities consumed $12.6 million during the nine months ended September 30, 2013. This cash outflow was entirely related to the repayment of debt. During the nine months ended September 30, 2012, financing activities consumed $4.2 million. Components of cash flow from financing activities during the nine months ended September 30, 2012 include the repayment of debt in the amount of $12.2 million, new borrowings in the amount of $8.0 million and the provision of $50,000 through the issuance of common stock.
Critical Accounting Policies
For detailed descriptions of our significant accounting policies, we refer you to the corresponding section of Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2012 (please see pages 74 to 77).
Future Operations
Management intends to continue the development of our oil and gas portfolio as well as seek additional investment opportunities in the oil and natural gas sector. Long term, we intend to fund the holding and permitting costs associated with the Mt. Emmons property.
Effects of Changes in Prices
Natural resource operations are significantly affected by changes in commodity prices. As prices for a particular commodity increase, values for prospects for that commodity typically also increase, making acquisitions of such properties more costly and sales potentially more valuable. Conversely, a price decline could enhance acquisitions of properties related to that commodity, but could also make sales of such properties more difficult. Operational impacts of changes in commodity prices are common in the oil and gas and mining industries.
At September 30, 2013, we are receiving revenues from our oil and gas business. Our revenues, cash flows, future rate of growth, results of operations, financial condition and ability to finance projected acquisitions of oil and gas producing assets are dependent upon prevailing prices of oil and gas.
Forward Looking Statements
This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (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. When used in this Form 10-Q, the words “will”, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Forward-looking statements in this Form 10-Q include statements regarding our expected future revenue, income, production, liquidity, cash flows, reclamation and other liabilities, expenses and capital projects, future capital expenditures and future
transactions. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements due to a variety of factors, including those associated with our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil, NGL and natural gas prices, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for our participation in oil and gas properties and for future acquisitions, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas and minerals businesses. In particular, careful consideration should be given to cautionary statements made in the Company’s Risk Factors included in our Annual Report on Form 10-K and other quarterly reports on Form 10-Q filed with the SEC, all of which are incorporated herein by reference. The Company undertakes no duty to update or revise any forward-looking statements.
Forward-looking statements also include those relating to the permitting and approval process for the Mount Emmons Molybdenum Project (the “Project”).There can be no assurance that U.S. Energy will receive the permits and approvals necessary to pursue the Project. In addition, such permits and approvals, if received, could be unreasonably or unexpectedly delayed or made subject to conditions that reduce the benefits of the Project or render it uneconomic. The process under NEPA may be longer than the Company expects, may involve substantial costs, and may require substantial management attention. The mine, if constructed, could be substantially different in nature, productivity and economic potential than the mine as contemplated by the MPO. In addition, if constructed, the operation of the mine will be subject to a wide variety of operating, commodity-price related and financial risks.
Off-Balance Sheet Arrangements
None
Contractual Obligations
We had three principal categories of contractual obligations at September 30, 2013: Debt to third parties of $7.2 million, executive retirement obligations of $871,000 and asset retirement obligations of $775,000.
The debt consists of $7.0 million in debt under the senior credit facility related to our oil and gas reserves and $200,000 in debt related to the purchase of land near our Mt. Emmons molybdenum property. Each borrowing under the senior credit facility has a term of six months but can be continued at our election through July 2017 if we remain in compliance with the covenants under the facility. The $200,000 land debt is due on January 2, 2014. The executive retirement liability will be paid out over varying periods starting after the actual retirement dates of the covered executives. The asset retirement obligations are expected to be retired during the next 34 years.
Commodity Risk.
Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, and this volatility will impact our revenues.
To mitigate some of our commodity risk, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and gas production. We may also use puts, calls and basis swaps in the future. We do not hold or issue derivative instruments for trading purposes. The objective of utilizing the economic hedges is to reduce the effect of price changes on a portion of our future oil production, to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. The use of these derivative instruments limits the downside risk of adverse price movements. However, there is a risk that such use may limit our ability to benefit from favorable price movements. Energy One may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of its existing positions.
Through Energy One, we have entered into commodity derivative contracts (“economic hedges”) with Wells Fargo and BNP Paribas, as described below. The derivative contracts are priced using West Texas Intermediate (“WTI”) quoted prices. The Company is a guarantor of Energy One’s obligations under the economic hedges.
Energy One's commodity derivative contracts as of September 30, 2013 are summarized below:
|
Quantity
|
|||||||||||||
|
Settlement Period
|
Counterparty
|
Basis
|
(Bbls/day)
|
Strike Price
|
|||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
10/01/12 - 09/30/13
|
BNP Paribas
|
WTI
|
200 |
Put:
|
$ | 95.00 | |||||||
|
Call:
|
$ | 116.60 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
07/01/13 - 09/30/13
|
Wells Fargo
|
WTI
|
400 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.50 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
10/01/13 - 12/31/13
|
Wells Fargo
|
WTI
|
600 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.50 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 95.00 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
01/01/14 - 06/30/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 97.25 | |||||||||||
|
Crude Oil Costless Collar
|
|||||||||||||
|
07/01/14 - 12/31/14
|
Wells Fargo
|
WTI
|
300 |
Put:
|
$ | 90.00 | |||||||
|
Call:
|
$ | 98.40 | |||||||||||
The following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:
|
As of September 30, 2013
|
||||||||||
|
(in thousands)
|
||||||||||
|
Derivative Assets
|
Derivative Liabilities
|
|||||||||
|
Balance Sheet
|
Fair
|
Balance Sheet
|
Fair
|
|||||||
|
Classification
|
Value
|
Classification
|
Value
|
|||||||
|
Crude oil costless collars
|
Current Asset
|
$ | 62 |
Current Liability
|
$ | 647 | ||||
These contracts are accounted for using the mark-to-market accounting method and accordingly, we recognize all unrealized and realized gains and losses related to these contracts currently in earnings and such gains and losses are classified as gain (loss) on derivative instruments, net in our consolidated statements of operations.
Evaluation of Disclosure Controls and Procedures
As of September 30, 2013, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:
|
i.
|
That the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure; and
|
|
ii.
|
That the Company’s disclosure controls and procedures are effective.
|
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Appeal of Modification – Notice of Intent (“NOI”) to Conduct Prospecting for the Mt. Emmons Project
On October 17, 2013, the Colorado Court of Appeals upheld the Colorado District Court and affirmed the Colorado Mined Land Reclamation Board (“MLRB”) approval of the Company’s Modification MD-03 (“MD-03”) to the NOI. Previously, on January 12, 2011, the MLRB had upheld DRMS’s approval of MD-03 and its determination that: i) the activities proposed by the NOI and MD-03 are prospecting, not development or mining, (ii) the current financial warranty amount is sufficient to cover the proposed activities and (iii) DRMS’s decision not to make its approval of MD-03 contingent on permits or licenses that may be required by federal, other state, or local agencies was proper.
Quiet Title Action – Dimmit County, TX
On October 4, 2013, Dimmit Wood Properties, Ltd. (“Dimmit”) filed a Quiet Title Action against Chesapeake Exploration, LLC (“Chesapeake”), Crimson Exploration Operating, Inc. (“Crimson”), EXCO Operating Company, LP, OOGC America, Inc., the Company’s subsidiary Energy One, LLC (“Energy One”) and Liberty Energy, LLC (“Liberty”) (jointly referred to as “Defendants”) concerning an 800.77 gross acre oil and gas lease (the “Lease”) located in Dimmit County, Texas. Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One has a 30% net interest. Dimmit alleges that the Lease has terminated due to the failure to achieve production in paying quantities. On October 28, 2013, the Defendants filed an answer stating that production in paying quantities was achieved in the primary term of the Lease with an existing producing well and the Lease has remained in good standing and has not terminated. The Defendants also filed counterclaims against Dimmit, including but not limited to breach of contract. No new wells have been drilled by the Defendants on the Lease.
There have been no other material changes from the legal proceedings as previously disclosed in our 2012 Form 10-K in response to Item 3 of Part I of such Form 10-K (pages 49-51) or the Form 10-Qs filed on May 10, 2013 and August 8, 2013 in response to Item 1 of Part II of such Form 10-Qs.
There have been no material changes to the risk factors discussed in Part I, “Item 1A - Risk Factors” (pages 16 to 31) in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, which may materially affect the Company’s business, financial condition or future results. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may materially adversely affect its business, financial condition and/or operating results.
None
Not Applicable
None
Not Applicable
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
||
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
||
|
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
|
||
|
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
|
||
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.
|
|||
|
(Registrant)
|
|||
|
Date: November 8, 2013
|
By:
|
/s/ Keith G. Larsen
|
|
|
KEITH G. LARSEN
|
|||
|
Chairman and CEO
|
|||
|
Date: November 8, 2013
|
By:
|
/s/ Steven D. Richmond
|
|
|
STEVEN D. RICHMOND
|
|||
|
Chief Financial Officer
|
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-43-
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 . Mine Safety DisclosuresItem 5. Other InformationItem 6 . Exhibits