Item 1 B - Unresolved Staff Comments.
None.
Item 2 - Properties
Oil and gas
The following table sets forth our net proved reserves as of the dates indicated. We do not have in-house geophysical or reserve engineering expertise. We therefore primarily rely on the operators of our producing wells who provide production data to our independent reserve engineers. Reserve estimates are based on 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. Reserve estimates as of December 31, 2016, 2015 and 2014 are based on the following average prices, in each case as adjusted for transportation, quality, and basis differentials applicable to our properties on a weighted average basis:
Presented below is a summary of our proved oil and gas reserve quantities as of the end of each of our last three fiscal years:
(1) Our reserve estimates as of December 31, 2016 and 2015 are based on reserve reports prepared by Jane E. Trusty, PE. Ms. Trusty is an independent petroleum engineer and a State of Texas Licensed Professional Engineer (License #60812). The reserve estimates provided by Ms. Trusty were based upon her review of the production histories and other geological, economic, ownership and engineering data, as provided by us or as obtained from the operators of our properties. A copy of Ms. Trusty’s report is filed as an exhibit to this report on Form 10-K.
(2) Our reserve estimates as of December 31, 2014 were based on the reserve report prepared by Cawley, Gillespie & Associates, Inc., or CGA. CGA is a nationally recognized independent petroleum engineering firm and is a Texas Registered Engineering Firm (F-693). Our primary contact at CGA is Mr. W. Todd Brooker, Senior Vice President and a State of Texas Licensed Professional Engineer (License #83462). The reserve estimates were based upon the review by CGA of the production histories and other geological, economic, ownership and engineering data, as provided by us or as obtained from the operators of our properties. A copy of CGA’s December 31, 2014 report was previously filed as an exhibit to our 2014 Annual Report on Form 10-K and is herein incorporated by reference as an exhibit to this report on Form 10-K.
As of December 31, 2016, our proved reserves totaled 887,142 BOE, of which approximately 100% were classified as proved developed. On a BOE basis, approximately 74% of the total is derived from 657,280 Bbls of oil and 26% is derived from 1,379,170 Mcf of natural gas. See the "Glossary of Oil and Gas Terms" for an explanation of these and other terms.
You should not place undue reliance on estimates of proved reserves. See “Risk Factors - Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.” A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetrics, material balance, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
We believe we maintain an effective system of internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information is assessed for validity when meetings are held with management, land personnel and third party operators to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve database as well and verified to ensure their accuracy and completeness. Our reserve database is currently maintained by Jane Trusty, PE. Ms. Trusty works with our personnel to review field performance, future development plans, current revenues and expense information. Following these reviews, the reserve database and supporting data is updated so that Ms. Trusty can prepare her independent reserve estimates and final report.
Proved Undeveloped Reserves. As of December 31, 2016, we did not book any proved undeveloped reserves. During 2015 our proved undeveloped reserves were 434,720 BOE of proved undeveloped reserves as of December 31, 2015. This decrease was primarily due to a continued depression in global commodity prices in 2016.
As of December 31, 2016, we have no proved undeveloped reserves that have been included in this category for more than five years and we have recorded no material proved undeveloped locations that were more than one direct offset from an existing producing well. As a result of the continued low oil price environment in 2016, we did not incur any capital expenditures to convert our proved undeveloped reserves to producing status and we do not intend to incur capital expenditures for this purpose in 2017.
Oil and Gas Production, Production Prices, and Production Costs. The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and gas for the years ended December 31, 2016, 2015 and 2014.
We encourage you to read this information in conjunction with the information contained in our financial statements and related notes included in Item 8 of this report on Form 10-K.
The following table provides a regional summary of our production for the years ended December 31, 2016, 2015 and 2014:
Drilling and Other Exploratory and Development Activities. The following table sets forth information with respect to development and exploratory wells in which we own an interest in during the periods ended December 31, 2016, 2015 and 2014.
The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations - General Overview in this Annual Report on Form 10-K.
Oil and Gas Properties, Wells, Operations and Acreage. The following table summarizes information about our gross and net productive wells as of December 31, 2016.
For purposes of the above table, a well with multiple completions in the same bore hole is considered one well. Wells are classified as oil or natural gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion. As of December 31, 2016, none of the wells in the above table contain multiple completions.
Acreage. The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2016.
As a non-operator, we are subject to lease expiration if the operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage will expire at the end of their respective primary terms unless we renew the existing leases, establish commercial production from the acreage or a “savings clause” is exercised. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have commenced. While we generally expect to test or establish production from most of our acreage prior to expiration of the applicable lease terms, there is no assurance that we can or will do so. As of December 31, 2016, all of our acreage in the Williston Basin and Louisiana is held by production. For our properties in Texas, the approximate expiration of our gross and net acres are set forth below:
(1) Includes acreage located in the Buda, Eagle Ford, and Austin Chalk areas of South Texas.
Present Activities. As of April 14, 2017 no wells were being drilled and no wells were pending completion on acreage in which we own working interests.
Real Estate
We own a 14-acre tract in Riverton, Wyoming with a two-story, 30,400 square foot office building. The first floor is rented to non-affiliates and government agencies; the second floor was formerly occupied by the Company. We are currently attempting to secure tenants for the vacant portion of this building but we are also considering an outright sale of the property.
In addition, we own three city lots covering 13.84 acres adjacent to our corporate office building in Fremont County, Wyoming. We intend to sell these properties without development. However, there can be no assurance that sales of any of these properties will be completed on the terms, or in the time frame, we expect or at all.
Uranium
Anfield Resources. In 2007, we sold all of our uranium assets for cash and stock of the purchaser, Uranium One Inc. (“Uranium One”). The assets sold included a uranium mill in Utah and unpatented uranium claims in Wyoming, Colorado, Arizona and Utah. Pursuant to the asset purchase agreement, we were entitled to additional consideration from Uranium One up to $40.0 million based on the performance of the mill, achievement of commercial production and royalties, but no additional consideration was ever received from Uranium One. In August 2014, we entered into an agreement with Anfield Resources Inc. (“Anfield”) whereby if Anfield was successful in acquiring the property from Uranium One, we agreed to release Anfield from the future payment obligations stemming from our 2007 sale to Uranium One. On September 1, 2015, Anfield acquired the property from Uranium One and is now obligated to provide the following consideration to us:
· Issuance of $2.5 million in Anfield common shares to us. The Anfield shares are to be held in escrow and released in tranches over a 36-month period. Pursuant to the agreement, if any of the share issuances result in the Company holding in excess of 20% of the then issued and outstanding shares of Anfield (the “Threshold”), such shares in excess of the Threshold would not be issued at that time, but deferred to the next scheduled share issuance. If, upon the final scheduled share issuance the number of shares to be issued exceeds the Threshold, the value in excess of the Threshold is payable to us in cash,
· $2.5 million payable in cash upon 18 months of continuous commercial production, and
· $2.5 million payable in cash upon 36 months of continuous commercial production.
The first tranche of common shares resulted in the issuance of 7,436,505 shares of Anfield with a market value of $750,000 and such shares were delivered to us in September 2015. The second tranche of shares resulted in the issuance of 3,937,652 additional shares of Anfield with a market value of $750,000, and such shares were delivered to us in September 2016. Since the trading volume in Anfield shares has increased since we took possession, we determined a mark-to-market technique would be the most appropriate method to determine the fair value for Anfield shares. The primary factor in using a mark-to-market valuation in determining the fair value of Anfield shares is justified because of our belief that due to the increased liquidity in the stock, using current market prices for Anfield shares reflects the most accurate fair value calculation. At December 31, 2016, we determined the fair value of the Anfield shares to be approximately $0.9 million. The timing of any future receipt of cash from Anfield is not determinable and there can be no assurance that any cash will ever be received from Anfield or that the shares received from Anfield will ever be liquidated for cash.
Royalty on Uranium Claims. We hold a 4% net profits interest on certain unpatented mining claims on Rio Tinto’s Jackpot uranium property located on Green Mountain in Wyoming. To date, we have not received any payments related to this royalty and there can be no assurance that any amount will ever be received.
Marketing, Major Customers and Delivery Commitments
Markets for oil and gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is marketed by our industry partners for our benefit and is sold to competing buyers, including large oil refining companies and independent marketers. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. We had no material delivery commitments as of December 31, 2016.
Competition
The oil and gas business is highly competitive in the search for and acquisition of additional reserves and in the sale of oil and gas. Our competitors principally consist of major and intermediate sized integrated oil and gas companies, independent oil and gas companies and individual producers and operators. In particular, we compete for property acquisitions and our operating partners compete for the equipment and labor required to operate and develop our properties. Our competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.
Item 3 - Legal Proceedings
Material legal proceedings pending at December 31, 2016 and developments in those proceedings through April 14, 2017 are summarized below.
Statoil ASA
In June 2011, Brigham Oil & Gas, L.P. (“Brigham”), as the operator of the Williston 25-36 #1H Well, filed an action in the State of North Dakota, County of Williams, in District Court, Northwest Judicial District, Case No. 53-11-CV-00495 to interplead to the court with respect to the undistributed suspended royalty funds from this well to protect itself from potential litigation. Brigham became aware of an apparent dispute with respect to ownership of the mineral interest between the ordinary high water mark and the ordinary low water mark of the Missouri River. Brigham suspended payment of certain royalty proceeds of production related to the minerals in and under this property pending resolution of the apparent dispute. Brigham was subsequently sold to Statoil ASA (“Statoil”) who assumed Brigham’s rights and obligations under this case. The Company owns a working interest, not royalty interest, in this well and no funds have been withheld.
On January 28, 2013, the District Court Northwest Judicial District issued an Order for Partial Summary Judgment holding that the State of North Dakota as part of its title to the beds of navigable waterways owns the minerals in the area between the ordinary high and low watermarks on these waterways, and that this public title excludes ownership and any proprietary interest by riparian landowners. This issue has been appealed to the North Dakota Supreme Court. Our legal position is aligned with Statoil, who will continue to provide legal counsel in this case for the benefit of all working interest owners.
Reformed Assignments
We are also a party to litigation that seeks to reform certain assignments of mineral interests we acquired from Brigham. This matter involves the depth below the surface to which the assignments were effective. The plaintiff is seeking to reform the agreement such that our assignment would be revised to be 12 feet closer to the surface. This dispute affects one of our producing wells.
Quiet Title Action - Willerson Lease
In September 2013, we acquired from Chesapeake Exploration, LLC (“Chesapeake”) a 15% working interest in approximately 4,244 gross mineral acres in Dimmit County, Texas, that are leased from Dr. Darrell Willerson and affiliates (“Willerson”). In January 2014, Willerson inquired if their lease had terminated due to the failure to achieve production in paying quantities pursuant to the terms of the lease. Along with Crimson Exploration Operating, Inc. and Liberty Energy, LLC, we filed a declaratory judgment action in the District Court of Dimmit County in May 2014 seeking a determination from the court that the lease remains valid and in effect. Willerson counterclaimed for breach of contract, trespass, and related causes of action. In January 2016, Willerson filed a third-party petition alleging breach of contract, trespass, and related causes of action against Chesapeake and EXCO Operating Company, LP. The matter has settled with The Company’s portion being $75,000 plus the related legal fees. Legal fees are still being determined.
Arbitration of Employment Claim
A former employee has claimed that we owe up to $1.8 million under an Executive Severance and Non-Compete Agreement (the “Agreement”) due to a change of control and termination of employment without cause. The Agreement requires that any disputes be submitted to binding arbitration and a request for arbitration was submitted by the former employee in March 2016. We do not believe there is any merit to the claims of termination without cause or that a change of control occurred. Arbitration proceedings are expected to commence in 2017.
Item 4 - Mine Safety Disclosures
Not applicable.
PART II
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Market Information
Our common stock is traded on the over-the-counter market, and prices are reported on a "last sale" basis on the Nasdaq Capital Market. The following quarterly high and low closing sale prices reflects the Company’s 6 for 1 reverse common stock split which took effect June 22, 2016:
As of April 14, 2017, the closing sales price was $0.91 per share.
In order for us to maintain the listing of our shares of common stock on the NASDAQ Capital Market®, the common stock must maintain a minimum bid price of $1.00 as set forth in NASDAQ Marketplace Rule 5550(a)(2). If the closing bid price of the common stock is below $1.00 for 30 consecutive trading days, then the closing bid price of the common stock must be $1.00 or more for 10 consecutive trading days during a 180-day grace period to regain compliance with the rule. We cannot guarantee that we will be able to remain in compliance with the minimum price requirement within the grace period or satisfy other continued listing requirements. If our common stock is delisted from trading on the NASDAQ Capital Market, it may be eligible for trading over the counter, but the delisting of our common stock from NASDAQ could adversely impact the liquidity and value of our common stock. On March 27, 2017, we were given notice by the NASDAQ Capital Market that the closing price of our common stock has traded below $1.00 for 30 consecutive days. We have 180 calendar days to return to compliance.
Holders
As of April 14, 2017, there were approximately 808 shareholders of record, and we had 6,134,506 shares of common stock issued and outstanding.
Dividends
We did not declare or pay any cash dividends on common stock during fiscal years 2016 and 2015 and do not intend to declare any cash dividends in the foreseeable future. Our ability to pay dividends in the future is subject to limitations under state law and the terms of the Credit Facility, which restricts the ability of Energy One to pay dividends to the Company. Our ability to pay dividends on our common stock is also limited by the terms of our Series A Convertible Preferred Stock issued in February 2015. See Note 7 to the Consolidated Financial Statements herein and Management’s Discussion and Analysis of Financial Condition and Results of Operations-Recent Developments.
Issuance of Securities in 2016
During 2016, we issued a total of 351,000 shares of common stock to six directors of the Company pursuant to restricted stock grants under our 2012 Equity and Performance Incentive Plan.
On December 21, 2016, the Company completed a registered direct offering of 1,000,000 shares of common stock at a net price of $1.50 per share for total net proceeds of approximately $1.37 million. Additionally, the investors received warrants to purchase 1,000,000 shares of Common stock from the Company at an exercise price of $2.05 per share, subject to adjustment, for a period of five years from closing.
Item 6. Selected Financial Data
The following table sets forth selected supplemental financial and operating data as of the dates and periods indicated. The financial data for each of the five years presented were derived from our consolidated financial statements. The following data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This discussion includes forward-looking statements. Please refer to Cautionary Statement Regarding Forward-Looking Statements of this report on Form 10-K for important information about these types of statements. Additionally, please refer to the Glossary of Oil and Gas Terms of this report on Form 10-K for oil and gas industry terminology used herein.
General Overview
We are an independent energy company focused on the lease acquisition and development of oil and gas producing properties in the continental United States. Our business is currently focused in South Texas and the Williston Basin in North Dakota. However, we do not intend to limit our focus to these geographic areas. We continue to focus on increasing production, reserves, revenues and cash flow from operations while managing our level of debt.
We currently explore for and produce oil and gas through a non-operator business model; however, we may operate oil and gas properties for our own account and may expand our holdings or operations into other 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. As discussed in Item 1. Business, our long-term strategic focus is to develop operational capabilities through the pursuit of opportunities to acquire operated properties and/or operatorship of existing properties.
Recent Developments
On February 24, 2017, the Company received confirmation from IronHorse Resources, LLC (“Ironhorse”) of the termination of a previously announced agreement dated January 3, 2017.
The Company’s quarterly reserve reports are prepared based on a trailing 12-month average for benchmark oil and gas prices. The weighted average oil price used to prepare reserve estimates and to calculate the Full Cost Ceiling limitation for the year end of 2016 has increased. Assuming other variables remain substantially unchanged, the Company does not expect to record an impairment charge during the first quarter of 2017.
As of December 31, 2016, the Company was not in compliance with any of the financial covenants under its credit facility and on March 31, 2017, the lender did not provide a limited waiver for the Company’s noncompliance.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions. A summary of our significant accounting policies is detailed in Note 1 - Organization, Operations and Significant Accounting Policies in Item 8 of this report on Form 10-K. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.
Oil and Gas Reserve Estimates. Our estimates of proved reserves are based on quantities of oil and gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are critical estimates in determining our depreciation, depletion and amortization expense (“DD&A”) and our full cost ceiling limitation (“Full Cost Ceiling”). Future cash inflows are determined by applying oil and gas prices, as adjusted for transportation, quality and basis differentials to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Future production and development costs are based on costs existing at the effective date of the report. Expected cash flows are discounted to present value using a prescribed discount rate of 10% per annum.
Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data. Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics. We utilize independent reserve engineers to estimate our proved reserves at the end of each fiscal quarter during the year.
Oil and Gas Properties. We follow the full cost method in accounting for our 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 are amortized using the equivalent unit-of-production method, based on proved oil and gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the DD&A recognized in the period that the reserves are produced. DD&A is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our DD&A per unit. Costs associated with production and general corporate activities are expensed in the period incurred.
Exploratory wells in progress are excluded from the DD&A calculation until the outcome of the well is determined. Similarly, unproved property costs are initially excluded from the DD&A calculation. Unproved property costs not subject to the DD&A calculation consist primarily of leasehold and seismic costs related to unproved areas. Unproved property costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved oil and gas properties are assessed quarterly for impairment to determine whether we are still actively pursuing the project and whether the project has been proven either to have economic quantities of reserves or that economic quantities of reserves do not exist.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated DD&A and net of deferred income taxes may not exceed the Full Cost Ceiling. The Full Cost Ceiling is equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the unimpaired cost of unproved properties not subject to amortization, plus the lower of cost or fair value of unproved properties that are subject to amortization. When net capitalized costs exceed the Full Cost Ceiling, impairment is recognized.
Derivative Instruments. We use derivative instruments, typically costless collars and fixed-rate swaps, to manage price risk underlying our oil and gas production. We may also use puts, calls and basis swaps in the future. All derivative instruments are recorded in the consolidated balance sheets at fair value. We offset fair value amounts recognized for derivative instruments executed with the same counterparty. Although we do not designate any of our 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, we recognize all unrealized and realized gains and losses related to these contracts currently in earnings and they are classified as gain (loss) on oil price risk derivatives in our consolidated statements of operations.
Our Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties. The master contracts with approved counterparties identify the CEO as the Company representative authorized to execute trades.
Discontinued Operations- Mining Properties. Due to the disposition of our mining properties in February 2016, all of our mining properties are included in discontinued operations. Effective January 1, 2015, we adopted new accounting guidance related to the recognition and presentation of discontinued operations in our financial statements. Under the revised guidance, beginning in 2015 only disposals of businesses that represent strategic shifts that have a major effect on our operations and financial results are reported in discontinued operations. Accordingly, the disposal of our mining segment qualified for reporting as discontinued operations.
We capitalized all costs incidental to the acquisition of mining properties and related equipment. The costs of operating a related water treatment plant on the mine property, holding costs to maintain permits, mining exploration costs and general corporate overhead were expensed as incurred.
Joint Interest Operations. We do not serve as operator for any of our oil and gas properties. Therefore, we rely to a large extent on the operator of the property to provide us with timely and accurate information about the operations of the properties. Joint interest billings from the operators serve as our primary source of information to record revenue, operating expenses and capital expenditures for our properties on a monthly basis. Many of our properties are subject to complex participation and operating agreements where our working interests and net revenue interests are subject to change upon the occurrence of certain events, such as the achievement of “payout.” These calculations may be subject to error and differences of interpretation which can cause uncertainties about the proper amount that should be recorded in our accounting records. When these issues arise, we make every effort to work with the operators to resolve the issues promptly.
Revenue Recognition. We record oil and 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. Gas balancing obligations as of December 31, 2016 and 2015 were not significant.
Stock Based Compensation. We measure the cost of employee services received in exchange for all equity awards granted, including stock options, based on the fair market value of the award as of the grant date. We recognize the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. For awards granted which contain a graded vesting schedule, and the only condition for vesting is a service condition, compensation cost is recognized as an expense on a straight-line basis over the requisite service period as if the award was, in substance, a single award.
Recently Issued Accounting Standards
Please refer to the section entitled Recent Accounting Pronouncements under Note 1 - Organization, Operations and Significant Accounting Policies in Item 8 of this report on Form 10-K for additional information on recently issued accounting standards and our plans for adoption of those standards.
Results of Operations
Comparison of our Statements of Operations for the Years Ended December 31, 2016 and 2015
During the year ended December 31, 2016, we recorded a net loss of $14.1 million as compared to a net loss of $92.9 million for the year ended December 31, 2015. Our loss from continuing operations was $11.9 million for the year ended December 31, 2016 compared to a loss from continuing operations of $67.3 million for the year ended December 31, 2015. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the year ended December 31, 2016 compared to the year ended December 31, 2015.
Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the years ended December 31, 2016 and 2015 (dollars in thousands, except average sales prices):
The decrease in our oil sales of $4.4 million for the year ended December 31, 2016 resulted from a 40% reduction in our oil production and an 8% reduction in the average oil price realized during 2016 compared to 2015. The decrease in our gas sales of $0.2 million for the year ended December 31, 2016, was driven by a 19% decrease in our gas production during 2016 compared to 2015. The reduction in our net realized oil and gas prices is reflective of the continued global commodity price depression. During 2016, the differential between West Texas Intermediate (“WTI”) quoted prices for crude oil and the prices we realize for sales in the Williston Basin was approximately $6.00 per barrel lower. We expect this differential to continue (with the amount of the differential varying over time) and that our oil sales revenue will be affected by lower realized prices from this region.
For the year ended December 31, 2016, we produced 211,988 BOE, or an average of 581 BOE per day, as compared to 313,901 BOE or 860 BOE per day in 2015. Production for our Williston Basin properties decreased by 59,806 BOE during 2016, which is a 32% reduction compared to 2015. This decrease of 32% is consistent with the decrease in Williston Basin production as a result of normal production declines combined with lower working interests for wells that have achieved payout. Production for our Eagle Ford and Buda properties in South Texas decreased by 43,899 BOE during 2016, which is a 48% reduction compared to 2015. This reduction was attributable to the normal decline in production for wells in this area and we did not participate in further drilling in this area during 2016.
Oil and Gas Production Costs. Presented below is a comparison of our oil and gas production costs for the years ended December 31, 2016 and 2015 (dollars in thousands):
For the year ended December 31, 2016, production taxes decreased by $0.2 million compared to 2015. The decrease in production taxes is primarily a result of lower oil and gas sales. For the year ended December 31, 2016, lease operating expense decreased by $4.4 million which was primarily due to the implementation of cost reduction strategies by the operators of our wells, combined with a downward revision to our payable to major operator liability due to revised ownership interests in the associated properties.
Depreciation, depletion and amortization. Our DD&A rate for the year ended December 31, 2016 was $11.93 per BOE compared to $26.80 per BOE for 2015. 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. The primary factors that resulted in a reduction in our DD&A rate for the year ended December 31, 2016 were quarterly impairment charges that resulted from our quarterly Full Cost Ceiling limitations and a write down of our Proved Undeveloped reserves.
Impairment of oil and gas properties. During the years ended December 31, 2016 and 2015, we recorded impairment charges related to our oil and gas properties of $9.6 million and $57.7 million, respectively, because the net capitalized costs were in excess of the Full Cost Ceiling limitation. These quarterly impairment charges were primarily due to the deepening declines in global commodity prices. Presented below are the weighted average prices (before applying the impact of basis differentials between the benchmark prices and the actual prices realized for our wells) used to prepare our reserve estimates and to calculate our Full Cost Ceiling limitations for each of the four quarters in 2016, along with the impairment charges recognized during each of the four quarters in 2016 (dollars in thousands, except average prices):
Our quarterly reserve reports are prepared based on a trailing 12-month average for benchmark oil and gas prices. The weighted average oil price used to prepare reserve estimates and to calculate the Full Cost Ceiling limitation for the first quarter of 2017 is expected to increase from $42.75 to approximately $44.00 (both before further deductions for basis differentials). Assuming other variables remain substantially unchanged, we do not expect to record an impairment charge during the first quarter of 2017.
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the years ended December 31, 2016 and 2015 (dollars in thousands):
General and administrative expenses decreased by $3.1 million for the year ended December 31, 2016 compared to the year ended December 31, 2015. This decrease was primarily attributable to a reduction of $1.9 million, $0.7 million, and $0.5 million in compensation and benefits, stock based compensation, and employee severance costs, respectively. The reductions are attributable to a reduction in employees and overhead.
Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the years ended December 31, 2016 and 2015 (dollars in thousands):
We recognized a realized gain on oil price risk derivatives of $1.4 million for the year ended December 31, 2016 compared to a loss of $0.1 million for 2015. We recognized an unrealized loss on oil price risk derivatives of $1.6 million for the year ended December 31, 2016 compared to a gain of $1.6 million for 2015. The realized and unrealized loss for 2016 was $0.2 million compared to a realized and unrealized gain of $1.6 million for 2015.
During each of the years ended December 31, 2016 and 2015, we recorded a gain on the sale of assets of $0.1 million, which resulted from the sale of non-oil and gas related property and equipment. During the year ended December 31, 2016, we recorded a gain on investment of $0.8 million from the receipt of shares related to the disposition of a portion of our mining assets. During the year ended December 31, 2016, we determined that our marketable equity securities had experienced an impairment in value which resulted in an unrealized loss of $0.2 million. During the year ended December 31, 2016, we realized a gain on the revaluation of our outstanding warrants of $0.2 million. Our warrant liability is accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. No warrants were outstanding for the year ending December 31, 2015. We will continue to revalue our outstanding warrants on a quarterly basis.
Interest expense increased by $0.2 million during the year ended December 31, 2016 compared to 2015. This increase was primarily attributable to an increase in our weighted average borrowing for 2016.
Discontinued Operations. Due to the disposition of our mining properties in February 2016, all of our mining properties are included in discontinued operations for all periods presented in this report. At year end December 31, 2016 we recognized no impairment charge and December 31, 2015, we recognized an impairment charge of $22.6 million, respectively, when we determined that the carrying value could not be recovered. During the years ended December 31, 2016 and 2015, the costs of operating our water treatment plant on the mine property, holding costs to maintain permits, and general corporate overhead associated with the mine property were expensed as incurred. The total operating and holding expenses amounted to $2.1 million for the year ended December 31, 2016 compared to $3.0 million for 2015. The total operating and holding expense amount of $2.1 million for the year ended December 31, 2016 includes the value of the preferred stock issued as part of the transaction considerations.
Comparison of our Statements of Operations for the Years Ended December 31, 2015 and 2014
During the year ended December 31, 2015, we recorded a net loss of $92.9 million as compared to a net loss of $2.1 million for the year ended December 31, 2014. Our loss from continuing operations was $67.3 million for the year ended December 31, 2015 compared to a loss from continuing operations of $1.0 million for the year ended December 31, 2014. In the following sections we discuss our revenue, operating expenses, non-operating income, and discontinued operations for the year ended December 31, 2015 compared to the year ended December 31, 2014.
Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the years ended December 31, 2015 and 2014 (dollars in thousands, except average sales prices):
The decrease in our oil sales of $19.3 million for the year ended December 31, 2015, was driven by a 33% decrease in our oil production and a 52% reduction in average oil price realized. The decrease in our gas sales of $2.8 million for the year ended December 31, 2015 resulted from a 32% reduction in our gas production and a 55% reduction in the average gas price realized during 2015 compared to 2014. The differential between Nymex quoted prices for crude oil and the prices we realized for sales in the Williston Basin ranged from $11.00 to $6.00 per barrel during 2015. For the year ended December 31, 2015, we produced 313,901 BOE, or an average of 860 BOE per day, as compared to 465,342 BOE or 1,275 BOE per day in 2014. Production for our Eagle Ford and Buda properties in South Texas decreased by 91,437 BOE during 2015, which is a 50% reduction compared to 2014. These reductions were attributable to the normal decline in production for wells in this area and we did not participate in further drilling in this area during 2015 as a result of normal production declines and lower working interests in wells drilled in this region.
Oil and Gas Production Costs. Presented below is a comparison of our oil and gas production costs for the years ended December 31, 2015 and 2014 (dollars in thousands):
For the year ended December 31, 2015, production taxes decreased by $1.7 million as a result of the reduction in oil and gas sales. For the year ended December 31, 2015, lease operating expense decreased by $1.5 million due to a decrease in the number of producing wells per month.
Depreciation, depletion and amortization. Our DD&A rate for the year ended December 31, 2015 was $26.80 per BOE compared to $31.56 per BOE for 2014. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
Impairment of oil and gas properties. During the year ended December 31, 2014, the Company did not recognize any oil and gas impairment expense. During the year ended December 31, 2015, we recorded impairment charges related to our oil and gas properties of $57.7 million because the net capitalized costs were in excess of the Full Cost Ceiling limitation. These quarterly impairment charges were primarily due to the deepening declines in the price of oil during 2015. Presented below are the weighted average prices (before applying the impact of basis differentials between the benchmark prices and the actual prices realized for our wells) used to prepare our reserve estimates and to calculate our Full Cost Ceiling limitations for each of the four quarters in 2015, along with the impairment charges recognized during each of the four quarters in 2015 (dollars in thousands, except average prices):
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the years ended December 31, 2015 and 2014 (dollars in thousands):
General and administrative expenses decreased by $0.5 million for the year ended December 31, 2015 compared to the year ended December 31, 2014. This decrease was attributable to a reduction of $1.5 million in compensation and benefits, which was driven by (i) a decrease in executive retirement expense of $0.6 million since the actuarial calculations indicated the retirement plan was fully funded in 2015, (ii) a decrease in compensation and benefits of $0.6 million related to the retirement of two executive officers for all or part of 2015, (iii) a decrease in employee bonuses of $0.2 million, and (iv) a decrease in board of directors’ compensation of $0.1 million. Other significant changes in general and administrative expenses included (i) an increase in stock-based compensation which primarily resulted from the acceleration of vesting of stock options and restricted stock associated with employees who terminated employment in 2015, and (ii) an increase in severance expense of $0.5 million which was comprised of $0.4 million for 3 executive officers and $0.1 million for 6 other employees who terminated employment by the end of 2015.
Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the years ended December 31, 2015 and 2014 (dollars in thousands):
We recognized a realized loss on oil price risk derivatives of $0.1 million for the year ended December 31, 2015 compared to a gain of $0.3 million for 2014. We recognized an unrealized gain on oil price risk derivatives of $1.6 million for the year ended December 31, 2015 compared to a gain of $0.3 million for 2014. The realized and unrealized gain for 2015 was $1.6 million compared to a realized gain of $0.6 million for 2014, an improvement of $1.1 million which is indicative of the decline in the market for crude oil after we entered into the derivative contracts.
During each of the years ended December 31, 2015 and 2014, we recorded a gain on the sale of assets of $0.1 million, which resulted from the sale of non-oil and gas related property and equipment. During the year ended December 31, 2015, we determined that our marketable equity securities had experienced an other than temporary impairment in value which resulted in an unrealized loss of $0.1 million.
Interest expense decreased by $0.1 million during the year ended December 31, 2015 compared to 2014. This decrease was primarily attributable to a reduction in our weighted average borrowing for 2015.
Discontinued Operations. Due to the disposition of our mining properties in February 2016, all of our mining properties are included in discontinued operations for all periods presented in this report. As of December 31, 2015, we recognized an impairment charge of $22.6 million when we determined that the carrying value could not be recovered. During the years ended December 31, 2015 and 2014, the costs of operating our water treatment plant on the mine property, holding costs to maintain permits, and general corporate overhead associated with the mine property were expensed as incurred. The total operating and holding expenses amounted to $3.0 million for the year ended December 31, 2015 compared to $3.1 million for 2014.
Non-GAAP Financial Measures- Adjusted EBITDAX
Adjusted EBITDAX represents income (loss) from continuing operations as further modified to eliminate impairments, depreciation, depletion and amortization, stock-based compensation expense, loss on investments and non-operating income or expense, income taxes, unrealized derivative gains and losses, interest expense, exploration expense, and other items set forth in the table below. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated, such as the employee severance charges incurred in 2016.
Adjusted EBITDAX is a non-GAAP measure that is presented because we believe it provides useful additional information to investors and analysts as a performance measure. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our wholly-owned subsidiary, Energy One LLC, is also subject to a debt to adjusted EBITDAX ratio as one of the financial covenants under its Credit Facility and the calculation for purposes of the Credit Facility differs from our financial reporting definition.
The following table provides reconciliations of income (loss) from continuing operations to adjusted EBITDAX for the years ended December 31, 2016, 2015 and 2014, in thousands:
Liquidity and Capital Resources
The following table sets forth certain measures about our liquidity as of December 31, 2016 and 2015, in thousands:
(1) Working capital deficit is computed by subtracting total current liabilities from total current assets.
(2) The standardized measure is widely used in the oil and gas industry and is considered by lenders, institutional investors and professional analysts when comparing companies. See Note 16 to the consolidated financial statements included in Item 8 of this report on Form 10-K for further information about the standardized measure and changes therein.
(3) The current ratio is computed by dividing total current assets by total current liabilities.
(4) The debt to equity ratio is computed by dividing total debt by total shareholders’ equity.
As of December 31, 2016, we have a working capital deficit of $6.0 million compared to a working capital deficit of $9.8 million as of December 31, 2015, an improvement of $3.7 million. This improvement was primarily attributable to (i) the reclassification of historically disputed property ownership interests and (ii) an improvement in commodity prices in the 4th quarter of 2016.
Our sole source of debt financing is a revolving Credit Facility with Wells Fargo Bank N.A. With lower oil and gas prices during 2015, Wells Fargo decreased the borrowing base by $18.5 million to $6.0 million which is the borrowing base in effect as of December 31, 2016. Outstanding borrowings as of December 31, 2016 were $6.0 million, and the Company did not have any borrowing availability as of December 31, 2016. Accordingly, this debt is classified as a current liability as of December 31, 2016.
During 2015 and 2016, we did not maintain compliance with certain financial ratio covenants in the Credit Facility with Wells Fargo. In April 2016, Wells Fargo provided a waiver for non-compliance with the covenants in the Credit Facility for the fiscal quarter ended December 31, 2015. In August 2016 Wells Fargo agreed to enter into a fourth amendment to the Credit Facility that provides for, among other things, a limited waiver of the negative financial covenants for the fiscal quarters ended March 31, 2016 and June 30, 2016. The Company violated the financial ratio covenants for the fiscal quarters ended September 30, 2016 and December 31, 2016, which constitutes an event of default under the Credit Facility. Additionally, management expects that further non-compliance with the financial ratio covenants is likely during 2017. As a result of the Company’s non-compliance under this Credit Facility, Wells Fargo has the immediate right to demand acceleration of all outstanding borrowings and has the ability to foreclose upon the existing collateral. Wells Fargo notified the Company that default rate interest is accruing on all outstanding balances under the credit facility. While the lender has provided limited waivers for our past noncompliance, there is no assurance that it will continue to do so if we are non-compliant in the future. Currently, we do not have adequate funding to repay Wells Fargo if it declares our covenant non-compliance to be an event of default or if it elects to reduce the borrowing base below the amount of the outstanding balance. The ongoing availability of this Credit Facility through the maturity date of July 30, 2017, or our receipt of funding from alternative sources, is critical to our ability to survive and continue as a going concern. If we become unable to continue as a going concern, we may find it necessary to liquidate our assets or file a voluntary petition for reorganization under the Bankruptcy Code in order to provide us additional time to identify an appropriate solution to our financial situation and implement a plan of reorganization aimed at improving our capital structure.
On December 16, 2016, the Company entered into a securities purchase agreement, pursuant to which the Company agreed to sell 1,000,000 shares of its of its common stock for gross proceeds of $1.5 million.
During 2015 and 2014, we received significant overpayments due to an operator’s failure to timely recognize the payout implications of our joint operating agreements. During the second quarter of 2015, the operator corrected its records and has elected to begin withholding the net revenues from all of our wells that it operates to recover these overpayments. As of December 31, 2016, the balance of the overpayment was approximately $2.7 million and based on the oil and gas prices and costs used in our reserve report as of December 31, 2016, this liability is expected to be settled in late 2017.
We believe certain operators have failed to allocate our share of non-consent ownership interests which results in contingent liabilities to the extent we have not been billed for our proportionate share of such interests, and contingent assets to the extent that we have not received our share of the net revenues. We record net contingent liabilities for the obligations that we believe are probable which amounted to $1.4 million as of December 31, 2016. The ultimate resolution of these uncertainties about our working interests and net revenue interests can extend over a long period of time and we cannot provide any assurance that these matters will be resolved within the next year.
Our standardized measure decreased by $6.7 million during 2016 which was primarily associated with decreases in oil and gas prices. The reduction in our total assets and shareholders’ equity is primarily associated with our net loss of $14.1 million during 2016, as discussed under Results of Operations herein.
During 2016, we completed the following actions to improve our operating results going forward:
· In February 2016, we completed the disposition of our mining segment, including the Keystone Mine, a related water treatment plant and other related properties. While an impairment charge of $22.6 million was recognized related to this disposition, a significant objective for completing the disposition was to improve future profitability. Following the disposition, we are no longer required to operate the water treatment plant and will not be responsible for mine holding costs, which are expected to result in estimated annual cash savings of $3.0 million. We believe the disposition of our mining segment is a major step in the transformation of the Company to solely focus on our existing oil and gas business.
· In April 2016, our lender provided a limited waiver for our noncompliance with the financial covenants as of December 31, 2015.
· In August 2016, our lender provided the 4th amendment to our credit facility, providing a limited waiver for our noncompliance with the financial covenants as of June 30, 2016.
As of December 31, 2016, we had cash and equivalents of $2.5 million.
If we have needs for financing in 2017, alternatives that we will consider if necessary include selling or joint venturing an interest in some of our oil and gas assets, selling our real estate assets in Wyoming, selling our marketable equity securities, issuing shares of our common stock for cash or as consideration for acquisitions, and other alternatives, as we determine how to best fund our capital programs and meet our financial obligations.
Any potential capital expenditure plan and our ability to obtain sufficient funding to make anticipated capital expenditures and satisfy our financial obligations are subject to numerous risks and uncertainties, including the risk of continued low commodity prices or further reductions in those prices, the risk that breaches of covenants in our Credit Facility will not be waived and will result in liquidation, bankruptcy or similar proceedings, the risk that we will be unable to enter into additional financing arrangements on acceptable terms or at all, and numerous other risks, including those discussed in Risk Factors under Item 1A
Item 8 - Financial Statements and Supplementary Data
Financial statements meeting the requirements of Regulation S-X are included below.
Item 9
Item 9 - Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A
Item 9A - Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures. We are required to maintain disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are designed to ensure that required information is recorded, processed, summarized and reported within the required timeframe, as specified in the rules of the SEC. Our disclosure controls and procedures are also designed to ensure that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosures.
Based on an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of our fiscal year ended December 31, 2016, our Chief Executive Officer and Principal Financial Officer (both roles are currently held by the same individual) determined that our controls were not adequate due to a vacancy in certain accounting and finance consulting positions that the Company has historically utilized to implement the Company’s review of key controls in a timely manner. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Accordingly, based on this material weakness, our Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this Annual Report on Form 10-K, December 31, 2016, as it relates to the timely implementation of the Company’s review of key controls.
This material weakness resulted in no identified misstatements of the consolidated financial statements. The Company has addressed this weakness by filling the consulting vacancy with professionals with experience in implementing a full review of key controls on an ongoing basis.
Managements Report on Internal Control Over Financial Reporting. We are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act). We maintain a system of internal controls that is designed to provide reasonable assurance in a cost-effective manner as to the fair and reliable preparation and presentation of the consolidated financial statements in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Principal Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016. In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control-Integrated-Framework” (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) which. Based on the evaluation conducted under the framework in “Internal Control- Integrated Framework” issued by COSO, the Company’s management concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2016 for the reasons described above.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K.
Changes in Internal Control Over Financial Reporting. Other than the identified material weakness described above and the Company’s solution to address the identified material weakness, there have been no other changes to the Company’s system of internal control over financial reporting during the year and fiscal quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting. As part of a continuing effort to improve the Company’s business processes, management is currently evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.
Item 9B
Item 9B - Other Information
None
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
U.S. Energy Corp.
We have audited the accompanying consolidated balance sheets of U.S. Energy Corp. and subsidiary as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of U.S. Energy Corp. and subsidiary as of December 31, 2016 and 2015, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has a working capital deficit, an accumulated deficit, and has incurred recurring losses from operations. The Company is in default of its loan covenants for the year ending December 31, 2016 and is expected to remain out of compliance through maturity of the loan. Accordingly, the entire balance has been classified as a current liability as of December 31, 2016. While the lender has provided limited waivers for the Company’s past noncompliance, there is no assurance that it will continue to do so in the future. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters also are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ Hein & Associates LLP
Denver, Colorado
April 17, 2017
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2016 AND 2015
(In Thousands, Except Share and Per Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(In Thousands, Except Share and Per Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(In Thousands, Except Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(In Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS, Continued
FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014
(In Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
1. ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations
U.S. Energy Corp. (collectively with its subsidiaries Energy One LLC, Highlands Ranch LLC, and Remington Village, LLC referred to as the “Company”) was incorporated in the State of Wyoming on January 26, 1966. The Company’s principal business activities are focused in the acquisition, exploration and development of oil and gas properties in the United States.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“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 that are used in the calculation of depreciation, depletion, amortization and impairment of the carrying value of evaluated oil and gas properties; production and commodity price estimates used to record accrued oil and gas sales receivable; valuation of commodity derivative instruments; the impact of commodity prices and other events affecting impairment of mining properties; and the cost of future asset retirement obligations. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable. 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.
Principles of Consolidation
The accompanying financial statements include the accounts of the Company and its wholly-owned subsidiary Energy One LLC (“Energy One”). All inter-company balances and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to the current period presentation of the accompanying financial statements.
Cash and Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Oil and Gas Sales Receivable
The Company’s accounts receivable consist primarily of receivables from joint interest operators for the Company’s share of oil, gas, and natural gas liquids (“NGLs”). Generally, the Company’s oil and gas sales receivable are collected within three months and the Company has had minimal bad debts. Collectability is dependent upon the financial wherewithal of the joint interest operators and is influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2016 and 2015, the Company had not provided for an allowance for doubtful accounts.
Marketable Equity Securities
The Company categorizes its marketable equity securities as available-for-sale. Accordingly, increases or decreases in the fair value are generally presumed to be temporary and are recorded as a component of shareholders’ equity within comprehensive income or loss. The Company periodically evaluates if cumulative losses are indicative of other than temporary impairment whereby a loss is recognized when management determines that the value is unlikely to recover to the Company’s cost basis. Gains or losses from sales are recorded in operations when realized.
U.S. ENERGY CORP. AND SUBSIDIARIES
Oil and Gas Properties
The Company follows the full cost method of 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 are subject to depreciation, depletion and amortization (“DD&A”) using the equivalent unit-of-production method, based on total proved oil and gas reserves. For financial statement presentation, DD&A includes accretion expense related to asset retirement obligations. Excluded from amounts subject to DD&A are costs associated with unevaluated properties, including exploratory wells in progress.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability, or the cost center ceiling (the “Ceiling Test”). 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 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 the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of unevaluated 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 gas properties. If the net book value reduced by the related net deferred income tax liability (if any) 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. Since all of the Company’s oil and gas properties are located within the United States, the Company only has one cost center for which a quarterly Ceiling Test is performed.
Property 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 as follows:
Years
Real estate:
Buildings
20 to 45
Building improvements
10 to 25
Land improvements
10 to 35
Administrative assets:
Computers and software
3 to 10
Office furniture and equipment
5 to 20
Vehicles and other
Discontinued Operations- Mining Properties
Effective January 1, 2015, the Company adopted new accounting guidance related to the recognition and presentation of discontinued operations in its financial statements. Under the revised guidance, beginning in 2015 only disposals of businesses that represent strategic shifts that have a major effect on an organization’s operations and financial results will be reported in discontinued operations. Accordingly, as discussed in Note 6, the Company’s disposal of its mining segment qualified for reporting as discontinued operations in the accompanying financial statements.
The Company capitalized all costs incidental to the acquisition of mining properties. Mining equipment was depreciated using the straight line method over estimated useful lives that ranged from 10 to 20 years. Costs of operating a related water treatment plant on the mine property, holding costs to maintain permits, mining exploration costs and general corporate overhead were expensed as incurred. Capitalized costs were charged to operations to the extent it was subsequently determined that the mine property is not economic due to permanent decreases in market prices of commodities, excessive production costs, depletion of the mineral resource, or other factors.
Long-Lived Assets
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment charge is recognized, and measured as the amount by which the carrying value exceeds the estimated fair value. Changes in significant assumptions underlying future cash flow estimates may have a material effect on the Company’s financial position and results of operations.
Long-lived assets are classified as held for sale when the Company commits to a plan to sell the assets. Such assets are classified within current assets if there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to determine if there is any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.
Derivative Instruments
The Company uses derivative instruments, typically costless collars and fixed-rate swaps, 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 the Company’s 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 that are related to these contracts currently in earnings and classifies them as gain (loss) on derivative instruments, net in the Company’s consolidated statements of operations. The Company may also use puts, calls and basis swaps in the future.
Warrant Liability
From time to time we may have financial instruments such as warrants that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in our control, or (c) the instruments contain other provisions that causes us to conclude that they are not indexed to our equity. Such instruments are initially recorded at fair value and subsequently adjusted to fair value at the end of each reporting period through earnings. Accordingly, warrants are accounted for as a liability. This warrant liability is accounted for at fair value with changes in fair value reported in earnings.
Asset Retirement Obligations
The Company records the estimated fair value of restoration and reclamation liabilities related to its oil and gas properties and its inactive mining properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required, and accretion of the discounted liability is recorded based on the passage of time. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for restoration and reclamation during the quarter in which it occurs.
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, natural gas, and NGLs. In the accompanying statements of operations, revenue from gas includes sales of both natural gas and NGLs. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported separately as expenses and are included in lease operating expense in the accompanying statements of operations. The Company records oil and gas revenue under the sales method of accounting. Gas balancing obligations as of December 31, 2016 and 2015 were not significant. Revenue is recorded in the month that the production is delivered to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, their historical performance, market prices, and other factors as the basis for these estimates.
Revenues from real estate operations are reported on a gross revenue basis and are recorded at the time the service is provided.
Stock-Based Compensation
The Company measures the cost of employee and director services received in exchange for all equity awards granted, including stock options, based on the fair market value of the award as of the grant date. The Company computes the fair values of its options granted to employees using the Black Scholes pricing model. The Company recognizes the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. For awards granted which contain a graded vesting schedule, and the only condition for vesting is a service condition, compensation cost is recognized as an expense on a straight-line basis over the requisite service period as if the award was, in substance, a single award. Stock-based compensation expense is recognized based on awards ultimately expected to vest whereby estimates of forfeitures are based upon historical experience.
Income Taxes
The Company recognizes deferred income tax assets and liabilities for the expected future income tax consequences, based on enacted tax laws, of temporary differences between the financial reporting and tax bases of assets, liabilities and carry forwards.
Additionally, the Company recognizes deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards and tax credit carry forwards. Deferred tax assets are reduced, if deemed necessary, by a valuation allowance for any tax benefits which, based on current circumstances, are not expected to be realized. At December 31, 2016 and 2015, management believed it was more likely than not that such tax benefits would not be realized and a valuation allowance has been provided. The Company would recognize any interest and penalties related to uncertain tax positions as a component of income tax expense.
Earnings Per Share
Basic net income (loss) per share is computed based on the weighted average number of common shares outstanding. Diluted net income (loss) per share is calculated by dividing net income or loss by the diluted weighted average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options. When there is a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are excluded from the calculation of net income (loss) per share. The treasury stock method is used to measure the dilutive impact of in-the-money stock options.
Comprehensive Income (Loss)
Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders’ equity instead of net income (loss).
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers”. This comprehensive guidance will replace all existing revenue recognition guidance and is effective for annual reporting periods beginning after December 15, 2017, and interim periods therein. This update is not expected to have a significant impact on the Company’s financial statements.
In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern” that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. This ASU becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. This update did not have a significant impact on the Company’s financial statements.
In November 2014, the FASB issued ASU 2014-16, “Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity”. This ASU does not change the current criteria in GAAP for determining when separation of certain embedded derivative features in a hybrid financial instrument is required, but clarifies how current GAAP should be interpreted in the evaluation of the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share, reducing existing diversity in practice. This ASU became effective for interim periods beginning on January 1, 2016. This update did not have a significant impact on the Company’s financial statements.
In January 2015, the FASB issued ASU 2015-01, “Income Statement-Extraordinary and Unusual Items”, that will simplify income statement classification by removing the concept of extraordinary items from GAAP. Upon adoption, the separate disclosure of extraordinary items after income from continuing operations in the income statement will no longer be permitted. The Company adopted this standard as of January 1, 2016. This update did not have a significant impact on the Company’s financial statements.
In February 2015, the FASB issued ASU No. 2015-02, “Consolidation: Amendments to the Consolidation Analysis”. The new standard is intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures. The new guidance must be adopted for interim and annual financial statements issued for the year ending December 31, 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.
During 2015, the FASB issued ASUs No. 2015-03 and No. 2015-15 titled “Interest-Imputation of Interest”, which generally requires the presentation of debt issuance costs as a direct deduction from the carrying amount of the related debt liabilities. However, for debt issuance costs related to line-of-credit arrangements, the Company will be permitted to continue presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The Company does not have any outstanding deferred lines of credit at this time.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities. This ASU is intended to improve the recognition and measurement of financial instruments. Among other things, this ASU requires certain equity investments to be measured at fair value with changes in fair value recognized in net income. This guidance is effective for fiscal years beginning after December 15, 2017, and interim periods therein.
In February 2016, the FASB issued ASU 2016-02, Leases, which will supersede the existing guidance for lease accounting. This ASU will require lessees to recognize leases on their balance sheets, and leaves lessor accounting largely unchanged. This guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, and early adoption is permitted. This update did not have a significant impact on the Company’s financial statements.
2016-05
In March 2016, the FASB issued ASU 2016-06, Derivatives and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments clarify the steps required to assess whether a call or put option meets the criteria for bifurcation as an embedded derivative. The amendment is effective for fiscal years and interim periods beginning after December 1, 2016. This amendment is not expected to have a significant impact on the Company’s financial statements.
2016-06
In March 2016, the FASB issued ASU 2016-06, Derivatives and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments clarify the steps required to assess whether a call or put option meets the criteria for bifurcation as an embedded derivative. The amendment is effective for fiscal years and interim periods beginning after December 1, 2016. This amendment is not expected to have a significant impact on the Company’s financial statements.
2016-11
In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting ("ASU 2016-11"). The SEC Staff is rescinding the following SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Specifically, registrants should not rely on the following SEC Staff Observer comments upon adoption of Topic 606: a) Revenue and Expense Recognition for Freight Services in Process which is codified in 605-20-S99-2; b) Accounting for Shipping and Handling Fees and Costs, which is codified in paragraph 605-45-S99-1; c) Accounting for Consideration Given by a Vendor to a Customer, which is codified in paragraph 605-50-S99-1 and d) Accounting for Gas-Balancing Arrangements (that is, use of the “entitlements method”), which is codified in paragraph 932-10-S99-5. We do not use the entitlements method of accounting and are not impacted by this specific SEC Staff Observer comment; however, we are assessing the potential impact of other SEC Staff Observer comments included in ASU 2016-11 on our consolidated financial condition and results of operations.
2016-15
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-15 on our consolidated financial condition and results of operations.
2016-18
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) ("ASU 2016-18"). The amendments in this update require that a statement of cash flows explain the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. The Company is currently assessing the impact of ASU 2016-18 on our consolidated financial condition and results of operations.
2017-03
In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosures should be considered to assess the significance of the impact upon adoption. This ASU is effective for the annual period beginning after December 15, 2018, and for annual and interim periods thereafter. Early adoption is permitted. The Company is currently evaluating the new guidance to determine the impact it will have on its consolidated financial condition and results of operations.
2017-04
In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. ASU 2017-04 is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annual goodwill impairment tests performed after January 1, 2017. We are currently assessing the impact of ASU 2017-04 and date of adoption.
2017-05
In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This update is meant to clarify the scope of ASC Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as Update 2014-09. Further, the Company is required to adopt this guidance at the same time that it adopts the guidance in Update 2014-09. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial condition and results of operations.
2. LIQUIDITY
As of December 31, 2016, the Company has a working capital deficit of $6,042 and an accumulated deficit of $124,035. Additionally, the Company incurred a net loss of $14.1 million for the year ended December 31, 2016. During 2016, the Company was in violation of certain covenants in its credit agreement and the Company expects future violations in 2017, which requires the entire balance to be classified as a current liability. While the lender has provided limited waivers for the Company’s past noncompliance, there is no assurance that it will continue to do so in the future.
During the 2016, the Company completed the following actions which are expected to improve the Company’s operating results in 2017 and increase the ability of the Company to survive the current oil and gas industry price environment.
· In February 2016 the Company completed the disposition of its mining segment, including the Keystone Mine, a related water treatment plant and other related properties. While an impairment charge of $22,620 was recognized related to this disposition, a significant objective for completing the disposition was to improve future profitability. Following the disposition, the Company is no longer required to operate the water treatment plant and will not be responsible for mine holding costs, which are expected to result in estimated annual cash savings of $3,000. Management believes the disposition of the Company’s mining segment is a major step in the transformation of U.S. Energy Corp. to solely focus on its existing oil and gas business.
· On December 21, 2016, the Company completed a registered direct offering of 1,000,000 shares of common stock at a net price of $1.50 per share. Concurrently, the investors received warrants to purchase 1,000,000 shares of Common Stock of the Company at an exercise price of $2.05 per share, subject to adjustment, for a period of five years from closing. The total net proceeds received by the Company was approximately $1.32 million. The fair value of the warrants upon issuance was $1.24 million, with the remaining $0.08 million being attributed to common stock. The warrants contain a dilutive issuance and other liability provisions which cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded as a liability and are accounted for at fair value with changes in fair value reported in earnings.
As of December 31, 2016, the Company had cash and equivalents of $2.5 million. Management also expects potential investors and lenders may find the Company’s new singular industry focus, combined with attractive producing properties and a low-cost overhead structure, make the Company an attractive vehicle to partner with during this industry downturn and low commodity price environment provided that the Company is able to address the challenges posed by the upcoming maturity of its Wells Fargo Credit Facility on July 30, 2017.
3. OIL PRICE RISK DERIVATIVES
The Company’s wholly-owned subsidiary Energy One has entered into crude oil derivative contracts (“economic hedges”) with Wells Fargo, the Company’s lender as discussed further in Note 7. The derivative contracts are priced based on West Texas Intermediate (“WTI”) quoted prices for crude oil. 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 the Company’s future oil production, achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage the Company’s 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 the Company’s 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. As of December 31, 2016, the Company did not have any outstanding crude oil derivative contracts.
Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are included in unrealized gain (loss) on oil price risk derivatives in the consolidated statements of operations.
4. OIL AND GAS PRODUCING ACTIVITIES
Acquisitions
In May 2014, the Company entered into a Participation Agreement to acquire a 33% interest in approximately 12,100 gross (3,384 net) acres in Dimmit County, Texas. The Company’s share of the acreage consists of 4,020 gross (1,181 net) acres of primary leasehold acreage and 8,080 gross (2,203 net) acres of farm-in acreage, to be earned through a continuous drilling program. The farm-in acreage had an initial two well commitment and a 12.5% carried working interest for the leaseholder (the “Farmor”) in the first 10 wells. After 100% payout of all costs for the first 10 wells that are drilled under the farm-in program, the Farmor will back in for its 12.5% retained working interest in the prospect. The Seller also retained a 25% back-in working interest after 115% of project payout has been received by the Company. The Company paid approximately $3,900 to enter into the transaction, which included leasehold and farm-in acquisition costs as well as a proportionate share of drilling costs for the initial test well in the prospect. As of December 31, 2016, approximately $252 is included in unevaluated properties and the remainder of the costs are included in evaluated properties.
Divestitures
In May 2014, the Company entered into an agreement to sell some of its Williston Basin assets. Under the terms of the agreement, the Company sold its interest in approximately 286 net acres and 16 gross (0.62 net) producing wells in Williams and McKenzie Counties, North Dakota. The transaction closed in June 2014 with an effective date of January 1, 2014. The Company received approximately $12,200 at closing which included $681 in adjustments related to revenue receivable and accounts payable through the date of closing. The balance of the sale proceeds of approximately $11,500 was recorded as a reduction of evaluated properties in the full cost pool.
As discussed in Note 10, in April 2015 the Company settled a quiet title action that was initiated in October 2013, whereby the Company received $1,500 in exchange for releasing its interest in the subject lease. Accordingly, the proceeds from the settlement were accounted for as a reduction of the Company’s evaluated oil and gas properties in 2015.
Ceiling Test and Impairment
The reserves used in the Ceiling Test incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In the calculation of the Ceiling Test for the year ended December 31, 2016, the Company used $42.75 per barrel for oil and $2.48 per MMbtu for natural gas (as further adjusted for property specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. The discount factor used was 10%.
For the years ended December 31, 2016 and 2015, impairment of the Company’s oil and gas properties amounted to $9.6 million and $57.7 million, respectively. These impairment charges were primarily due to a decline in the price of oil, additional capitalized well costs and changes in production. Recent declines in the price of oil have significantly increased the risk of Ceiling Test write-downs in future periods.
Capitalized Costs
The following table presents the Company’s capitalized costs associated with oil and gas producing activities as of December 31, 2016 and 2015:
The Company’s depreciation, depletion and amortization per equivalent BOE was $11.93 for 2016, $26.80 for 2015, and $31.56 for 2014.
Unevaluated Oil and Gas Properties
Unevaluated oil and gas properties consist of leasehold costs and exploratory wells in progress which are excluded from the DD&A calculation and the Ceiling Test until a determination about the existence of proved reserves can be completed. As of December 31, 2016, unevaluated oil and gas properties consisted solely of unproved lease acquisition costs of $4.7 million. As of December 31, 2015, unevaluated oil and gas properties consisted solely of unproved lease acquisition costs of $5.7 million.
During the fourth quarter of 2015, the Company transferred approximately $2,500 of unproved properties that were considered to be impaired into the full cost pool. On a quarterly basis, management reviews market conditions and other changes in circumstances related to the Company’s unevaluated properties and transfers the costs to evaluated properties within the full cost pool as warranted.
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration and development activities, all of which have been capitalized, are summarized as follows for the years ended December 31, 2016, 2015 and 2014:
(1) Includes amounts related to estimated asset retirement obligations reduction of $(24) and additions $61 for the years ended December 31, 2016 and 2015, respectively. The development costs and exploration costs include a reduction in interest of some wells which in prior years were in dispute.
Results of Operations
Presented below are the results of operations from oil and gas producing activities for the years ended December 31, 2016, 2015 and 2014:
5. PROPERTY AND EQUIPMENT, NET
Property and equipment consists of the following as of December 31, 2016 and 2015:
Depreciation expense related to real estate and administrative assets amounted to $142, $145 and $148 for the years ended December 31, 2016, 2015 and 2014, respectively.
6. DISCONTINUED OPERATIONS
Disposition of Mining Segment
In February 2006, the Company reacquired the Mt. Emmons molybdenum mining properties (the “Property”). The Company has not conducted any extractive mining operations at the Property since its reacquisition but the Company was obligated under existing permits to operate a water treatment plant (“WTP”) and to incur holding costs associated with the retention of the mining properties, which resulted in aggregate annual expenses of approximately $3,000 during each of the three years in the period ended December 31, 2015.
The market price for molybdenum oxide was approximately $11 per pound during 2013 and 2014 with a decrease to approximately $5 per pound by the fourth quarter of 2015. In light of the considerable ongoing costs related to the Property and the deteriorating market for molybdenum, during 2015 the Company began to explore the viability of alternative structures to the development of the Property that could result in a sharing or elimination of the ongoing costs and liabilities.
In February 2016, the Company’s Board of Directors decided to dispose of the Property rather than continuing the Company’s long-term development strategy whereby the Company entered into the following agreements:
A.The Company entered into an Acquisition Agreement (the “Acquisition Agreement”) with Mt. Emmons Mining Company, a subsidiary of Freeport-McMoRan Inc. (“MEM”), whereby MEM acquired the Property which consists of the Mt. Emmons mine site located in Gunnison County, Colorado, including the Keystone Mine, the WTP and other related properties. Under the Acquisition Agreement, MEM replaced the Company as the permittee and operator of the WTP and will discharge the obligation of the Company to operate the WTP from and after the closing in accordance with the applicable permits issued by the Colorado Department of Public Health and Environment. The Company did not receive any cash consideration for the disposition; the sole consideration for the transfer was that MEM assumed the Company’s obligations to operate the WTP and to pay the future mine holding costs for portions of the Property that it desires to retain.
As a result of the subsequent disposition of the Property as described above, the Company determined that an impairment charge of $22,620 was required to be recorded in the fourth quarter of 2015. Presented below is calculation of the impairment charge:
Under U.S. GAAP, the disposal of a segment is reported as discontinued operations in the Company’s financial statements. Presented below are the assets and liabilities associated with the Company’s mining segment as of December 31, 2016 and 2015, along with the impact of the impairment charge:
B. Concurrent with entry into the Acquisition Agreement and as additional consideration for MEM to accept transfer of the Property, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the “Series A Purchase Agreement”) with MEM, whereby the Company issued 50,000 shares of newly designated Series A Convertible Preferred Stock (the “Preferred Stock”) in exchange for (i) MEM accepting the transfer of the Property and replacing the Company as the permittee and operator of the WTP, and (ii) the payment of $1 to the Company. The Series A Purchase Agreement contains customary representations and warranties on the part of the Company. As contemplated by the Acquisition Agreement and the Series A Purchase Agreement and as approved by the Company’s Board of Directors, the Company filed with the Secretary of State of the State of Wyoming Articles of Amendment containing a Certificate of Designations with respect to the Preferred Stock (the “Certificate of Designations”). Pursuant to the Certificate of Designations, the Company designated 50,000 shares of its authorized preferred stock as Series A Convertible Preferred Stock. The Preferred Stock will accrue dividends at a rate of 12.25% per annum of the Adjusted Liquidation Preference (as defined); such dividends are not payable in cash but are accrued and compounded quarterly in arrears. The “Adjusted Liquidation Preference” is initially $40 per share of Preferred Stock for an aggregate of $2,000, with increases each quarter by the accrued quarterly dividend. The Preferred Stock is senior to other classes or series of shares of the Company with respect to dividend rights and rights upon liquidation. No dividend or distribution will be declared or paid on junior stock, including the Company’s common stock, (1) unless approved by the holders of Preferred Stock and (2) unless and until a like dividend has been declared and paid on the Preferred Stock on an as-converted basis.
At the option of the holder, each share of Preferred Stock may initially be converted into 13.33 shares of the Company’s $0.01 par value Common Stock (the “Conversion Rate”) for an aggregate of 666,667 shares. The Conversion Rate is subject to anti-dilution adjustments for stock splits, stock dividends and certain reorganization events and to price-based anti-dilution protections. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the ratio of the initial conversion value to the conversion value as adjusted for accumulated dividends multiplied by the Conversion Rate. In no event will the aggregate number of shares of Common Stock issued upon conversion be greater than 793,349 shares. The Preferred Stock will generally not vote with the Company’s Common Stock on an as-converted basis on matters put before the Company’s shareholders. The holders of the Preferred Stock have the right to approve specified matters as set forth in the Certificate of Designations and have the right to require the Company to repurchase the Preferred Stock in connection with a change of control.
During the first quarter of 2017, the Company expects to record the fair value of the Preferred Stock based on the initial liquidation preference of $2,000. Since the cash consideration paid by MEM for the Preferred Stock was a nominal amount, the Company expects to record a charge to operations of approximately $2,000 associated with the issuance.
C. Concurrent with entry into the Acquisition Agreement and the Series A Purchase Agreement, the Company and MEM entered into an Investor Rights Agreement, which provides MEM rights to certain information and Board observer rights. MEM has agreed that it, along with its affiliates, will not acquire more than 16.86% of the Company’s issued and outstanding shares of Common Stock. In addition, MEM has the right to demand registration of the shares of Common Stock issuable upon conversion of the Preferred Stock under the Securities Act of 1933, as amended.
Combined Results of Operations for Discontinued Operations
The results of operations of the discontinued mining and apartment complex operations are presented separately for all periods presented in the accompanying financial statements. Presented below are the components for the years ended December 31, 2016, 2015 and 2014:
7. DEBT
Energy One, a wholly-owned subsidiary the Company, has a credit facility with Wells Fargo Bank, National Association (“Wells Fargo”). As of December 31, 2016 and 2015, outstanding borrowings under the credit facility amounted to $6,000. As of December 31, 2016 and 2015, the borrowing base was $6,000. Borrowings under the credit facility are collateralized by Energy One’s oil and gas producing properties and substantially all of the Company’s cash and equivalents. Each borrowing under the agreement has a term of six months, but can be continued at the Company’s election through July 2017 if the Company remains in compliance with the covenants under the credit facility. The weighted average interest rate on this debt is 3.20% as of December 31, 2016.
Energy One is required to comply with customary affirmative covenants and with certain negative covenants. The principal negative financial covenants do not permit (i) the interest coverage ratio (EBITDAX to interest expense) to be less than 3.0 to 1; (ii) total debt to EBITDAX to be greater than 3.5 to 1; and (iii) the current ratio to be less than 1.0 to 1.0. EBITDAX is defined in the Credit Agreement as consolidated net income, plus non-cash charges. Additionally, the Credit Agreement prohibits or limits Energy One’s ability to incur additional debt, pay cash dividends and other restricted payments, sell assets, enter into transactions with affiliates, and to merge or consolidate with another company. The Company is a guarantor of Energy One’s obligations under the Credit Agreement.
In July 2015, the Company and Wells Fargo Bank entered into a third amendment (the "Third Amendment") to the agreement governing the credit facility (as amended, the "Senior Credit Agreement"). The Third Amendment provides for, among other things: (i) a limited waiver with respect to the restricted payments covenant pursuant to which a transfer of $5,000 from Energy One to the Company was permitted in 2015; (ii) a limited waiver of the current ratio covenant as it relates to the fiscal quarters ended June 30, 2015 and September 30, 2015; and (iii) a borrowing base of $7,000, subject to further adjustment from time to time in accordance with the Senior Credit Agreement. In December 2015, Wells Fargo made a further reduction in the borrowing base to $6,000.
In August 2016, the Company and Wells Fargo Bank entered into a fourth amendment (the “Fourth Amendment”) to the agreement governing the Credit Facility. The Fourth Amendment provides for, among other things, a limited waiver of the negative financial covenants for the fiscal quarters ended March 31, 2016 and June 30, 2016.
As of December 31, 2016, Energy One and the Company were not in compliance with any of the financial covenants and are not expected to regain compliance before the maturity of the credit facility on July 30, 2017.
Because the Company projects that it is unlikely that Energy One will regain compliance with all of the financial covenants within the next 12 months, outstanding borrowings of $6,000 are presented as a current liability in the accompanying consolidated balance sheet as of December 31, 2016. In the event that Energy One is unable to obtain an amendment or waiver of the Senior Credit Agreement to address the anticipated future breaches of the financial covenants, and other actual or potential future breaches that may occur, Wells Fargo could elect to declare some or all of the Company’s debt to be immediately due and payable and could elect to terminate its commitment and cease making further loans.
8. EXECUTIVE RETIREMENT AND SEVERANCE
In October 2005, the Board of Directors adopted an Executive Retirement Policy (the “Retirement Plan”) for the benefit of certain executive officers of the Company. To be eligible to participate in the Retirement Plan, the executive officer was required to serve as one of the designated executive officers for at least 15 years, reached the age of 60, and been an employee of the Company on December 31, 2010. Upon retirement, the executive was entitled to cash payments equaling 50% of the greater of (i) the amount of compensation earned as base cash pay on the final regular pay check or (ii) the average annual pay, less all bonuses, received over the last five years of employment with the Company. The Company periodically engaged the services of a third party actuary to determine the estimated liability under the Retirement Plan. Presented below is a summary of changes in the liability for the years ended December 31, 2016 and 2015:
As of December 31, 2016 and 2015, the current portion of the Company’s liability under the Retirement Plan amounted to $0 and $583, respectively. These amounts are included in accrued compensation and benefits in the accompanying consolidated balance sheets, and the remainder of the liability is included in other long-term liabilities. Total compensation expense under the Retirement Plan for the years ended December 31, 2016 and 2015 was $3 and $45, respectively. In order to fund the Retirement Plan obligation, the Company periodically made cash contributions to a separate trust account that was managed by an independent trustee. As of December 31, 2014, the Company had funded $1,291 in the trust account, which is recorded as other long term assets in the consolidated balance sheet as of December 31, 2014. The trust account was invested in debt and equity securities until December 2015 when the trust was terminated and the investments were liquidated for cash in the amount of $1,271 which was included in cash and equivalents as of December 31, 2015. The Company and the Retirement Plan participants mutually agreed to terminate the Retirement Plan in December 2015, and all obligations were settled through cash payments during the first quarter of 2016.
In connection with the early retirement of the former COO, effective January 1, 2015 the Company entered into a 12-month consulting agreement with an affiliate of the former executive to provide assistance with matters related to the Company’s mining properties. The total payments under the consulting agreement amounted to $274, which is included in mine property holding costs within discontinued operations in the accompanying statement of operations for the year ended December 31, 2015.
During 2016, the Company made total payments of $3 for employee severance. During 2015, the Company entered into severance agreements with three former executive officers that provided for total payments of $379. The Company also incurred severance costs of $125 related to other employees of the Company, resulting in total severance expense of $504 for the year ended December 31, 2015.
9. ASSET RETIREMENT OBLIGATIONS
The following is a reconciliation of the changes in the Company’s liabilities for asset retirement obligations for the years ended December 31, 2016 and 2015:
As discussed further in Note 6, asset retirement obligations related to the Company’s mining segment are presented as discontinued operations in the accompanying balance sheets.
10. COMMITMENTS AND CONTINGENCIES
Commitments
401(k) Plan. The Board of Directors of the Company adopted the U.S. Energy Corp. 401(k) Plan in 2004. The Company matches 50% of an employee’s salary deferrals up to a maximum contribution per employee of $4 annually. The Company’s contributions are included in compensation and benefits in the accompanying consolidated statements of operations and amounted to $0, $37, and $48 for the years ended December 31, 2016, 2015 and 2014, respectively. The Company cancelled the 401(k) Plan during 2016.
Lessee Operating Leases. In November 2015, the Company took assignment of a lease agreement for office space in Denver, Colorado. The future minimum rental commitment under this sublease requires payments of $59 in 2017, when the sublease expires.
Lessor Operating Leases. The Company is the lessor of portions of an office building in Riverton, Wyoming that used to serve as the Company’s corporate headquarters and which are accounted for as operating leases. Rental income under the agreements was $83, $103, and $95 for the years ended December 31, 2016, 2015 and 2014, respectively.
Letter of Credit. In connection with the Company’s sublease of office space in Denver, a security deposit was provided in the form of an irrevocable letter of credit for $35. The letter of credit expires in September 2017. Collateral for the letter of credit is a certificate of deposit for $35 that is included in other assets in the accompanying balance sheet as of December 31, 2016.
Contingencies
From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the Company’s financial position or results of operations. Following are currently pending legal matters:
North Dakota Properties. On June 8, 2011, Brigham Oil & Gas, L.P. (“Brigham”), as the operator of the Williston 25-36 #1H Well, filed an action in the State of North Dakota, County of Williams, in District Court, Northwest Judicial District, Case No. 53-11-CV-00495 to interplead to the court with respect to the undistributed suspended royalty funds from this well to protect itself from potential litigation. Brigham became aware of an apparent dispute with respect to ownership of the mineral interest between the ordinary high water mark and the ordinary low water mark of the Missouri River. Brigham suspended payment of certain royalty proceeds of production related to the minerals in and under this property pending resolution of the apparent dispute. Brigham was subsequently sold to Statoil ASA (“Statoil”) who assumed Brigham’s rights and obligations under this case. The Company owns a working interest, not royalty interest, in this well and no funds have been withheld.
On January 28, 2013, the District Court Northwest Judicial District issued an Order for Partial Summary Judgment holding that the State of North Dakota as part of its title to the beds of navigable waterways owns the minerals in the area between the ordinary high and low watermarks on these waterways, and that this public title excludes ownership and any proprietary interest by riparian landowners. This issue has been appealed to the North Dakota Supreme Court. The Company’s legal position is aligned with Brigham, who will continue to provide legal counsel in this case for the benefit of all working interest owners.
The Company is also a party to litigation that seeks to reform certain assignments of mineral interests it acquired from Brigham. This matter involves the depth below the surface to which the assignments were effective. The plaintiff is seeking to reform the agreement such that the Company’s assignment would be revised to be 12 feet closer to the surface. This dispute affects one of the Company’s producing wells.
The ultimate outcome of these matters cannot presently be determined. However, in management’s opinion the likelihood of a material adverse outcome is remote. Accordingly, adjustments, if any, that might result from the resolution of this matter have not been reflected in the accompanying consolidated financial statements.
Quiet Title Actions. In October 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., Energy One and Liberty Energy, LLC (“Liberty”) (jointly referred to as “Defendants”) concerning an 801 gross acre oil and gas lease (“Lease”) located in Dimmit County, Texas. Crimson, Energy One and Liberty received an assignment from Chesapeake of the Lease, in which Energy One had a 30% working interest. Dimmit alleged that the Lease terminated due to the failure to achieve production in paying quantities and for having non-existent production for allegedly significant time periods. In April 2015, the Company, Crimson and Liberty agreed to settle the action whereby the Company received $1,500 in exchange for releasing its interest in the subject lease. Accordingly, the proceeds from the settlement were accounted for as a reduction of the Company’s evaluated oil and gas properties in 2015.
In September 2013, the Company acquired from Chesapeake a 15% working interest in approximately 4,244 gross mineral acres referred to as the Willerson lease. In January 2014, Willerson inquired if their lease had terminated due to the failure to achieve production in paying quantities pursuant to the terms of the lease. The Company along with Crimson and Liberty filed a declaratory judgment action in the District Court of Dimmit County in May 2014 seeking a determination from the court that the lease remains valid and in effect. The lessors counterclaimed for breach of contract, trespass, and related causes of action. In January 2016, the lessors filed a third-party petition alleging breach of contract, trespass, and related causes of action against Chesapeake and EXCO Operating Company, LP. As of December 31, 2016, unevaluated oil and gas properties includes $1,171 related to the leasehold costs that are subject to this matter. Adjustments, if any, that might result from the resolution of this matter have not been reflected in the accompanying consolidated financial statements. The matter has settled in 2017 with the Company’s portion being $75,000 plus the related legal fees. Legal fees are still being determined.
Arbitration of Employment Claim. A former employee has claimed that the Company owes up to $1,800 under an Executive Severance and Non-Compete agreement (the “Agreement”) due to a change of control and termination of employment without cause. The Agreement requires that any disputes be submitted to binding arbitration and a request for arbitration was submitted by the parties in March 2016. Management does not believe there is any merit to the claim of termination without cause or that a change of control occurred. A date has not yet been established for the arbitration proceedings. The ultimate outcome of this arbitration cannot presently be determined. Accordingly, adjustments, if any, that might result from the resolution of this matter have not been reflected in the accompanying consolidated financial statements.
Contingent Ownership Interests. As of December 31, 2016, the Company had recognized a contingent liability associated with uncertain ownership interests of $1,430. This liability arises when the calculations of respective joint ownership interests by operators differs from the Company’s calculations. These differences relate to a variety of matters, including allocation of non-consent interests, complex payout calculations for individual wells and groups of wells, along with the timing of reversionary interests. Accordingly, these matters are subject to legal interpretation and the related obligations are presented as a contingent liability in the accompanying consolidated balance sheet as of December 31, 2016. While the Company has classified this entire amount as a current liability, most of these issues are expected to be resolved through arbitration, mediation or litigation; due to the complexity of the issues involved, there can be no assurance that the outcome of these contingencies will be resolved during 2017.
Contingent Gain for Joint Interest Audit Recoveries. The Company has performed joint interest audits of certain drilling, completion and operating costs charged by the Major Operator discussed in Note 15. The results of the audits indicated that $5,269 of costs incurred by the Major Operator in 2011 and 2012 were improperly charged to the accounts for all of the joint interest owners in the wells, including $1,919 related to the Company. During 2015, the Major Operator agreed to issue refunds to the joint interest owners for aggregate charges of $606, aggregate charges for $4,432 were denied, and aggregate charges for $231 are pending further review. The Company has disputed the $4,432 of denied charges, of which its share is approximately $1,600. Since the Company previously paid the full amounts billed by the Major Operator, the dispute will be resolved in accordance with the terms of the joint operating agreements. Except for the refunds issued during 2015, no amounts have been recorded in the accompanying consolidated financial statements for additional recoveries that may result from the joint interest audits.
Anfield Gain Contingency. In 2007, the Company sold all of our uranium assets for cash and stock of the purchaser, Uranium One Inc. (“Uranium One”). The assets sold included a uranium mill in Utah and unpatented uranium claims in Wyoming, Colorado, Arizona and Utah. Pursuant to the asset purchase agreement, the Company was entitled to additional consideration from Uranium One up to $40,000 based on the performance of the mill, achievement of commercial production and royalties, but no additional consideration was ever received from Uranium One. In August 2014, the Company entered into an agreement with Anfield Resources Inc. (“Anfield”) whereby if Anfield was successful in acquiring the property from Uranium One, Anfield would be released from the future payment obligations stemming from the 2007 sale to Uranium One. On September 1, 2015, Anfield acquired the property from Uranium One and is now obligated to provide the following consideration to the Company:
· Issuance of $2,500 in Anfield common shares to the Company. The Anfield shares are to be held in escrow and released in tranches over a 36-month period. Pursuant to the agreement, if any of the share issuances result in the Company holding in excess of 20% of the then issued and outstanding shares of Anfield (the “Threshold”), such shares in excess of the Threshold would not be issued at that time, but deferred to the next scheduled share issuance. If, upon the final scheduled share issuance the number of shares to be issued exceeds the Threshold, the value in excess of the Threshold is payable to the Company in cash,
· $2,500 payable in cash upon 18 months of continuous commercial production, and
· $2,500 payable in cash upon 36 months of continuous commercial production.
The first tranche of common shares resulted in the issuance of 7,436,505 shares of Anfield with a market value of $750,000 and such shares were delivered to us in September 2015. The second tranche of shares resulted in the issuance of 3,937,652 additional shares of Anfield with a market value of $750,000, and such shares were delivered to us in September 2016. Since the trading volume in Anfield shares has increased since we took possession, we determined a mark-to-market technique would be the most appropriate method to determine the fair value for Anfield shares. The primary factor in using a mark-to-market valuation in determining the fair value of Anfield shares is justified because of our belief that due to the increased liquidity in the stock, using current market prices for Anfield shares reflects the most accurate fair value calculation. At December 31, 2016, we determined the fair value of the Anfield shares to be approximately $0.9 million. The timing of any future receipt of cash from Anfield is not determinable and there can be no assurance that any cash will ever be received from Anfield or that the shares received from Anfield will ever be liquidated for cash.
11. SHAREHOLDERS’ EQUITY
Preferred Stock
The Company’s articles of incorporation authorize the issuance of up to 100,000 shares of preferred stock, $0.01 par value. Shares of preferred stock may be issued with such dividend, liquidation, voting and conversion features as may be determined by the Board of Directors without shareholder approval. The Company is authorized to issue 50,000 shares of Series P preferred stock in connection with a shareholder rights plan that expired in 2011. As discussed in Note 6, in February 2016 the Board of Directors approved the designation of 50,000 shares of Series A Convertible Preferred Stock in connection with the disposition of the Company’s mining segment.
Warrants
On December 21, 2016, the Company completed a registered direct offering of 1,000,000 shares of common stock at a net price of $1.50 per share. Concurrently, the investors received warrants to purchase 1,000,000 shares of Common Stock of the Company at an exercise price of $2.05 per share, subject to adjustment, for a period of five years from closing. The total net proceeds received by the Company was approximately $1.32 million. The fair value of the warrants upon issuance was $1.24 million, with the remaining $0.08 million being attributed to common stock. The warrants contain a dilutive issuance and other liability provisions which cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded as a liability and are accounted for at fair value with changes in fair value reported in earnings.
Stock Option Plans Employee Stock Option Plans. In December 2001 the Board of Directors adopted, and the Company’s shareholders subsequently approved, the U.S. Energy Corp. 2001 Incentive Stock Option Plan (the "2001 ISOP"). The 2001 ISOP, as subsequently amended and approved by the Company’s shareholders, reserved for issuance 25% of the Company’s shares of common stock issued and outstanding at any time. The 2001 ISOP had a term of 10 years which expired in December 2011. Accordingly, no options may be granted under the 2001 ISOP; as of December 31, 2016, options for a total of 360,746 shares are outstanding under the 2001 ISOP and expire on various dates through September 2018.
In June 2012 the Board of Directors adopted, and the shareholders subsequently approved, the U.S. Energy Corp. 2012 Equity and Performance Incentive Plan (the “2012 Equity Plan”). The 2012 Equity Plan, as amended and approved by shareholders in June 2015, reserves for issuance to the Company’s employees and Directors a total of 3,200,000 shares of the Company’s common stock. The 2012 Equity Plan has a term of 10 years which expires in June 2022. As of December 31, 2016, options for a total of 390,525 shares are outstanding under the 2012 Equity Plan and expire on various dates through January 2025.
Director and Advisory Board Members Option Plan. In June 2008 the Board of Directors adopted, and the shareholders subsequently approved, the 2008 Stock Option Plan for U.S. Energy Corp. Independent Directors and Advisory Board Members (the "2008 Director SOP"). The 2008 Director SOP reserved for issuance 1.0% of the Company’s shares of common stock issued and outstanding at any time. The 2008 Director SOP had an original term of 10 years. However, as a result of shareholder approval in June 2015 of an amendment to the 2012 Equity Plan, no additional options may be granted under the 2008 Director SOP. As of December 31, 2016, options for a total of 29,779 shares are outstanding under the 2008 Director SOP and expire on various dates through September 2024.
A summary of the combined activity in the 2001 ISOP, the 2012 Equity Plan, and the 2008 Director SOP for the years ended December 31, 2016, 2015 and 2014 is as follows:
(1) Represents the weighted average price.
No stock options were exercised during the years ended December 31, 2016 and 2015. During the year ended December 31, 2014, a total of 427,537 stock options were exercised through the payment of nominal cash consideration and the surrender of 257,253 shares valued at $1,106. The aggregate intrinsic value of options exercised in 2014 was $788.
The following table summarizes information for stock options outstanding and for stock options exercisable at December 31, 2016:
The following table sets forth the number of options available for grant as well as the intrinsic value of the options outstanding and exercisable as of December 31, 2016, 2015 and 2014:
In connection with severance agreements entered into with employees during 2015, an aggregate of 1,617,689 outstanding stock options would have expired upon termination of employment. However, the Company agreed to permit exercise until the original expiration dates specified in the option agreements. Accordingly, the Company determined the fair value of the options at the date of modification and recorded additional compensation expense which amounted to an aggregate of $109.
As of December 31, 2016, no shares are available for future grants under the Company’s stock option plans. Based upon the closing price for the Company’s common stock of $1.28 per share on December 30, 2016, there was no intrinsic value related to stock options outstanding as of December 31, 2016.
For the years ended December 31, 2016, 2015 and 2014, total stock-based compensation expense associated with stock options, including the modification charge discussed above, was $213, $948 and $318, respectively. As of December 31, 2016, there was $80 of unrecognized expense related to unvested stock options, which will be recognized as stock-based compensation expense through January 2018. The weighted average fair value per share for options granted for the years ended December 31, 2015 and 2014 was $0.88 and $2.27, respectively, and no options were granted in 2016. In estimating the fair value of options, the Company used the Black-Scholes option-pricing model with the following weighted average assumptions:
Restricted Stock Grants. In January 2015, the Board of Directors granted 340,711 shares of restricted stock under the 2012 Equity Plan to four officers of the Company. These shares originally vested annually over a period of three years. However, during 2015 vesting was accelerated for three of the four officers as a condition of severance agreements. Accordingly, 240,711 shares vested in 2015 and the officers elected to surrender an aggregate of 88,637 shares in exchange for the Company’s agreement to fund their payroll tax liabilities associated with the fair value of the shares on the dates of vesting.
On September 23, 2016, the Board of Directors granted restricted stock to each member of the Board for 58,500 shares per Board member for an aggregate grant of 351,000 shares. Such shares vest for 50% of the shares on September 23, 2017 and the remaining 50% of the shares vest on September 23, 2018. The closing price of the Company’s common stock on the grant date was $1.74, which will result in an aggregate compensation charge of $611 over the two-year vesting period.
The 351,000 shares of restricted common stock were granted pursuant to the Company’s 2012 Equity Plan, which provides that each grant constitutes an immediate transfer of ownership that entitles the Board members to voting, dividend and other ownership rights. However, the shares of restricted stock are subject to a substantial risk of forfeiture until vesting occurs. Prior to vesting, the shares are not permitted to be sold or transferred and the directors do not maintain physical custody of the shares.
Employee Stock Ownership Plan
The Board of Directors of the Company adopted the U.S. Energy Corp. 1989 Employee Stock Ownership Plan ("ESOP") in 1989, for the benefit of all the Company’s employees. Employees become eligible to participate in the ESOP after one year of service which must consist of at least 1,000 hours worked. Employees become 20% vested after three years of service and increase their vesting by 20% each year thereafter until such time as they are fully vested after seven years of service.
On an annual basis, the Company historically contributed shares of its common stock to the ESOP with an aggregate fair value equal to 10% of compensation for employees that were eligible to participate. Employees were not eligible for ESOP contributions to the extent that their annual taxable compensation exceeded $265 for 2015. All shares of the Company’s common stock contributed to the ESOP have been allocated to specific employees and are vested. Total shares held by the ESOP as of September 30, 2016 and December 31, 2015 were 90,112 and 131,518, respectively. In September 2016, the Company’s Board of Directors agreed to terminate the ESOP, which is expected to result in a distribution of the remaining shares held by the ESOP to the vested employees during the first quarter of 2017.
For the year ended December 31, 2016, total stock-based compensation expense related to the ESOP was $23. No expense related to the ESOP has been recorded since June 30, 2016 since the Company’s Board of Directors has not determined if a discretionary contribution will be made for 2016. On July 7, 2016, the Board of Directors elected to issue 68,128 shares of the Company’s common stock with a fair value of $2.49 per share to settle this obligation.
12. INCOME TAXES
The Company incurred a net loss for each of the years ended December 31, 2016, 2015 and 2014, and the Company has recorded valuation allowances for its net deferred tax assets for each of those years. Accordingly, the Company has not recognized a benefit for income taxes in the accompanying financial statements. Income tax benefit using the Company’s effective income tax rate differs from the U.S. Federal Statutory income tax rate due to the following:
The components of deferred tax assets and liabilities as of December 31, 2016 and 2015 are as follows:
The Company has net operating loss carryovers as of December 31, 2016 of approximately $74,715 for federal income tax purposes. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset future taxable income and expire in varying amounts through 2035. In addition, the Company has alternative minimum tax credit carry-forwards of approximately $700 which are available to offset future federal income taxes over an indefinite period.
The statute of limitations is closed for the tax years through 2010. The Company recognizes, measures, and discloses uncertain tax positions whereby tax positions must meet a “more-likely-than-not” threshold to be recognized. During the years ended December 31, 2016, 2015 and 2014, no adjustments were recognized for uncertain tax positions.
13. EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding. The calculation of diluted earnings (loss) per share adds dilutive stock options computed using the treasury stock method as follows:
For the years ended December 31, 2016, 2015 and 2014, common stock equivalents excluded from the calculation of weighted average shares because they were antidilutive are as follows:
14. SIGNIFICANT CONCENTRATIONS
The Company has exposure to credit risk in the event of nonpayment by the joint interest operators of the Company’s oil and gas properties. During the years ended December 31, 2016, 2015 and 2014, three joint interest operators accounted for the following percentages of the Company’s oil and gas sales:
Approximately 22% of the Company’s proved developed oil and gas reserve quantities are associated with wells that are operated by operator B (the “Major Operator”) as shown in the table above. As of December 31, 2016, the Company had a liability to the Major Operator of $2,710 for accrued operating expenses and overpayments of net revenues when the Major Operator failed to recognize that the Company’s ownership interest reverted after payout was achieved for certain wells during 2014 and 2015. Beginning in the second quarter of 2015, the Major Operator began withholding the Company’s net revenues from all wells that it operates for the Company and management expects the Major Operator will continue to withhold the Company’s net revenues until this liability is paid in full. Based on the oil and gas prices and costs used in the Company’s reserve report as of December 31, 2016, this liability is expected to be settled in full by the first quarter of 2017, but under higher pricing scenarios it is possible that the entire liability could be repaid earlier. Accordingly, the aggregate balance of $2,710 is presented as a current liability in the accompanying consolidated balance sheet as of December 31, 2016.
Substantially all of the Company’s cash and equivalents are in accounts with a single financial institution and the balances typically exceed federally insured limits. The Company has not experienced any losses in such accounts.
During the years ended December 31, 2015 and 2014 the Company operated in two business segments, the oil and gas industry and the mining industry. As discussed in Note 6, in February 2016 the Company disposed of its mining operations and, accordingly, the mining operations and assets are presented under discontinued operations in the accompanying financial statements.
15. FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company uses various methods including market, income and cost approaches. Based on these approaches, the Company often utilizes certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable inputs. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Based on the observability of the inputs used in the valuation techniques the Company is required to provide the following information according to the fair value hierarchy. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values. Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:
Level 1 - Quoted prices for identical assets and liabilities traded in active exchange markets, such as the New York Stock Exchange.
Level 2 - Observable inputs other than Level 1 including quoted prices for similar assets or liabilities, quoted prices in less active markets, or other observable inputs that can be corroborated by observable market data. Level 2 also includes derivative contracts whose value is determined using a pricing model with observable market inputs or can be derived principally from or corroborated by observable market data.
Level 3 - Unobservable inputs supported by little or no market activity for financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation; also includes observable inputs for nonbinding single dealer quotes not corroborated by observable market data.
The Company has processes and controls in place to attempt to ensure that fair value is reasonably estimated. The Company performs due diligence procedures over third-party pricing service providers in order to support their use in the valuation process. Where market information is not available to support internal valuations, independent reviews of the valuations are performed and any material exposures are evaluated through a management review process.
While the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. The following is a description of the valuation methodologies used for complex financial instruments measured at fair value :
Oil Price Risk Derivative Valuation Methodologies
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of the counterparty and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the likelihood that the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. There were no derivative contracts in place at December 31, 2016. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Warrant Valuation Methodologies
The warrants contain a dilutive issuance and other liability provisions which cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded and valued as a level 3 liability and are accounted for at fair value with changes in fair value reported in earnings.
The Company estimated the value of the warrants issued with the Securities Purchase Agreement on December 21, 2016 to be $1,240,000, or $1.24 per warrant, using the Monte Carlo model with the following assumptions: a term expiring June 21, 2022, exercise price of $2.05, volatility rate of 90%, and a risk-free interest rate of 2.12%. The Company remeasured the warrants as of December 31, 2016, using the same Monte Carlo model, using the following assumptions: a term expiring June 21, 2022, exercise price of $2.05, stock price of $1.28, average volatility rate of 90%, and a risk-free interest rate of 2.01%. As of December 31, 2016, the fair value of the warrants was $1,030,000, or $1.03 per warrant, and was recorded as a liability on the accompanying consolidated balance sheets. An increase in any of the variables would cause an increase in the fair value of the warrants. Likewise, a decrease in any variable would cause a decrease in the value of the warrants.
Marketable Equity Securities Valuation Methodologies
The fair value of available for sale securities is based on quoted market prices obtained from independent pricing services. Accordingly, the Company has classified these instruments as Level 1.
Executive Retirement Liability Valuation Methodologies
The executive retirement program is a standalone liability for which there is no available market price, principal market, or market participants. The Company records the estimated fair value of the long-term liability for estimated future payments under the executive retirement program based on the discounted value of estimated future payments associated with each individual in the program. The inputs available for this estimate are unobservable and are therefore classified as Level 3 inputs.
Other Financial Instruments
The carrying amount of cash and equivalents, oil and gas sales receivable, other current assets, accounts payable and accrued expenses approximate fair value because of the short-term nature of those instruments. The recorded amounts for the Senior Secured Revolving Credit Facility discussed in Note 7 approximates the fair market value due to the variable nature of the interest rates, and the fact that market interest rates have remained substantially the same since the latest amendment to the credit facility.
Recurring Fair Value Measurements
Recurring measurements of the fair value of assets and liabilities as of December 31, 2016 and 2015 are as follows:
(1) Due to a less active market for this investment, during the fourth quarter of 2015 the Company transferred this investment from Level 1 to Level 2 of the fair value hierarchy.
(2) Because the trading volume of Anfield shares have increased since we took possession, we determined a mark-to-market technique would be most appropriate to determine the fair value for Anfield shares. Previously, the Company used alternative methods to determine fair value upon receipt of the shares in September 2015, which requires classification under Level 3 of the fair value hierarchy. The Company has reclassified the Anfield shares under Level 1 of the fair value hierarchy.
The following table presents a reconciliation of changes in assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2016 and 2015:
16. UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Oil and Gas Reserves (Unaudited)
Proved reserves are estimated quantities of oil, NGLs and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Oil and gas prices used are the average price during the 12-month period prior to the effective date of the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements. Proved developed reserves are reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and gas reserve quantities at December 31, 2016, 2015 and 2014 and the related discounted future net cash flows before income taxes are based on the estimates prepared by Jane E. Trusty for 2016 and 2015 and by Cawley, Gillespie & Associates, Inc. for 2014. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. All of the Company’s estimated proved reserves are located in the United States.
The Company’s estimated quantities of proved oil and gas reserves and changes in net proved reserves are summarized below for the years ended December 31, 2016, 2015 and 2014:
(1) Mcf equivalents (Mcfe) consist of natural gas reserves in mcf plus NGLs converted to mcf using a factor of 6 mcf for each barrel of NGL.
Standardized Measure (Unaudited)
The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.
Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure:
(1) Consists of the weighted average price for natural gas in mcf plus NGL’s converted to mcf using a factor of 6 mcf for each barrel of NGL.
Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor.
The standardized measure of discounted future net cash flows relating to the Company’s proved oil and gas reserves is as follows as of December 31, 2016, 2015 and 2014:
Changes in Standardized Measure (Unaudited)
The changes in the standardized measure of future net cash flows relating to proved oil and gas reserves for the years ended December 31, 2016, 2015 and 2014 are as follows:
17. QUARTERLY FINANCIAL DATA (Unaudited)
The Company’s quarterly financial information for the two-year period ended December 31, 2016 is as follows:
(1) Amounts have been restated from amounts reported in previous reports to retroactively present the impact of Discontinued Operations as discuss further in Note 6.
(2) Earnings per share amounts may not sum due to rounding.
The Company’s quarterly reserve reports are prepared based on a trailing 12-month average for benchmark oil and gas prices. The weighted average oil price used to prepare reserve estimates and to calculate the Full Cost Ceiling limitation for the first quarter of 2017 is expected to increase. Assuming other variables remain substantially unchanged, the Company does not expect to record an impairment charge during the first quarter of 2017.
As discussed in Note 7, as of December 31, 2016, the Company and Energy One were not in compliance with any of the financial covenants under their credit facilities and the lender has not provided a limited waiver for the Company’s noncompliance.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
PART III
In the event a definitive proxy statement containing the information being incorporated by reference into this Part III is not filed within 120 days of December 31, 2016, we will file such information under cover of a Form 10-K/A.
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
The information required by Item 10 with respect to directors and certain executive officers is incorporated herein by reference to our Proxy Statement for the Meeting of Shareholders, under the captions “Proposal 1: Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” and “Business Experience of Directors and Officers.” The other information required by Item 10 is also incorporated by reference herein to such Proxy Statement.
The Company has adopted a Code of Ethics. A copy of the Code of Ethics will be provided to any person without charge upon written request addressed to David A. Veltri, Chief Executive Officer, 4643 S. Ulster Street, Suite 970, Denver, Colorado 80237.
Item 11
Item 11 - Executive Compensation
The information required by Item 11 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders, under the captions “Executive Compensation” and “Non-Employee Director Compensation.”
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders, under the caption “Principal Holders of Voting Securities and Ownership by Officers and Directors.”
Item 13
Item 13 - Certain Relationships and Related Transactions, and Director Independence
The information required by Item 13 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders, under the caption “Certain Relationships and Related Transactions.”
Item 14
Item 14 - Principal Accounting Fees and Services
The information required by Item 14 is incorporated herein by reference to the Proxy Statement for the Meeting of Shareholders, under the caption “Principal Accountant Fees and Services.”
PART IV
Item 15
Item 15 - Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
The following financial statements are filed in Item 8 of this report:
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statement and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:
2.1**
Mt. Emmons Mining Company Acquisition Agreement (incorporated by reference from Exhibit 2.1 to the Current Report on Form 8-K filed February 12, 2016)
3.1**
Restated Articles of Incorporation (incorporated by reference from Exhibit 4.1 to the Company’s Registration Statement on Form S-3, [333-162607] filed October 21, 2009)
3.2**
Restated Bylaws, dated as of April 3, 2014 (incorporated by reference from Exhibit 3.2 to the Company’s Report on Form 8-K filed April 7, 2014)
3.3**
Certificate of Designation for Series A Convertible Preferred Stock (incorporated by reference from Exhibit 3.1 to the Current Report on Form 8-K filed February 12, 2016)
3.4**
Articles of Amendment to Restated Articles of Incorporation (incorporated by reference from Exhibit 3.1 to the Company’s Form 8-K filed June 21, 2016)
4.1**
Common Stock Purchase Warrant (incorporated by reference from Exhibit 4.1 to the Company’s Report on Form 8-K filed December 22, 2016)
10.1(a)**
BNP Paribas- Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed August 2, 2010)
10.1(b)**
Wells Fargo Bank, National Association - Second Amendment to Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 25, 2013)
10.1(c)**
Wells Fargo Bank, National Association - Third Amendment to Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 16, 2015)
10.1(d)**
Wells Fargo Bank, National Association - Fourth Amendment to Credit Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q filed August 15, 2016)
10.1(e)**
BNP Paribas - Mortgage Agreement (incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed August 2, 2010)
10.1(f)**
Wells Fargo Bank, National Association - Guaranty (incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed August 2, 2010)
10.2**†
USE 2001 Officers’ Stock Compensation Plan (incorporated by reference from Exhibit 4.21 to the Company’s Annual Report on Form 10-K filed September 13, 2002)
10.3**†
2001 Incentive Stock Option Plan (amended in 2003) (incorporated by reference from Exhibit 4.2 to the Company’s Annual Report on Form 10-K filed April 15, 2005)
10.4**
2008 Stock Option Plan for Independent Directors and Advisory Board Members (incorporated by reference from Exhibit 4.3 to the Company’s Annual Report on Form 10-K filed March 13, 2009)
10.5**†
U.S. Energy Corp. Employee Stock Ownership Plan (incorporated by reference from Exhibit 4.1 to the Company’s S-8 filed April 13, 2012)
10.6**†
Amended and Restated 2012 Equity and Performance Incentive Plan (incorporated by reference from Appendix A to the Company’s Proxy Statement on Form DEF14A filed April 28, 2015)
10.6.1**
Form of Grant to the 2012 Equity and Performance Incentive Plan (incorporated by reference from Exhibit 10.5.1 to the Form 10-K filed March 18, 2013)
10.7*
Amendment Assignment and Assumption Agreement (Anfield Resources and Uranium One) dated as of August 14, 2014
10.8(a)**†
Executive Employment Agreement - Keith G. Larsen (effective 4-20-12) (incorporated by reference from Exhibit 10.1 to the Form 8-K filed January 17, 2012)
10.8(b)** †
Executive Employment Agreement - David Veltri (effective 10-23-15) (incorporated by reference from Exhibit 10.2 to the Form 10-Q filed August 15, 2016)
10.8(c)**†
Agreement and Mutual Release of All Claims - Keith G. Larsen (effective 9-25-15) (incorporated by reference from Exhibit 10.8(b) to the Form 10-K/A filed April 29, 2016)
10.8(d)**†
Agreement and Mutual Release of All Claims - Steven D. Richmond (effective 12-31-15) (incorporated by reference from Exhibit 10.8(c) to the Form 10-K/A filed April 29, 2016)
10.8(e)**†
Agreement and Mutual Release of All Claims - Bryon G. Mowry (effective 12-31-15) (incorporated by reference from Exhibit 10.8(d) to the Form 10-K/A filed April 29, 2016)
10.8(f)**†
Form of Executive Severance and Non-Compete Agreement (incorporated by reference from Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)
10.9**
Agreement for Purchase of Leasehold Interests in McKenzie and Williams Counties, North Dakota (Brigham Oil & Gas, L.P.) (incorporated by reference from Exhibit 10.6 to the Company’s Annual Report on Form 10-K filed March14, 2012)
10.10(a)**
Agreement for Purchase of Leasehold Interests in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(a) to the Company’s Annual Report on Form 10-K filed March14, 2012)
10.10(b)**
Amendments (5) to Agreement for Purchase of Leasehold Interest in McKenzie County, North Dakota (Geo Resources, Inc.) (incorporated by reference from Exhibit 10.7(b) to the Company’s Annual Report on Form 10-K filed March14, 2012)
10.11(a)**
Participation Agreement between Energy One, LLC and Contango/Crimson effective February18, 2011 for the Leona River Project (incorporated by reference from Exhibit 10.10(a) to the Company’s Annual Report on Form 10-K filed March 12, 2014)
10.11(b)**
Participation Agreement between Energy One, LLC and Contango/Crimson effective April 1, 2011 for the Booth/Tortuga Project (incorporated by reference from Exhibit 10.10(b) to the Company’s Annual Report on Form 10-K filed March 12, 2014)
10.12**
Series A Convertible Preferred Stock Purchase Agreement (incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K filed February 12, 2016)
10.13**
Investor Rights Agreement (incorporated by reference from Exhibit 10.2 to the Current Report on Form 8-K filed February 12, 2016)
10.14**
Securities Purchase Agreement dated as of December 16, 2016 (incorporated by reference from Exhibit 10.1 to the Company’s Report on Form 8-K filed December 22, 2016)
14.0**
Code of Ethics (incorporated by reference from Exhibit 14 to the Company’s Annual Report on Form 10-K filed March 30, 2004)
21.1**
Subsidiaries of Registrant (incorporated by reference from Exhibit 21.1 to the Company’s Annual Report on Form 10-K filed on March 12, 2014)
23.1*
Consent of Independent Registered Accounting Firm (Hein & Associates LLP)
23.2*
Consent of Reserve Engineer (Jane E. Trusty, PE)
23.3*
Consent of Reserve Engineer (Cawley, Gillespie & Associates, Inc.)
31.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*
Certification of principal financial officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1*
Certification under Rule 13a-14(b) of Chief Executive Officer and principal financial officer
99.1*
Reserve Report (Jane E. Trusty, PE)
99.2**
Reserve Report (Cawley, Gillespie & Associates, Inc.) (incorporated by reference from Exhibit 99.1 to the Form 10-K filed March 12, 2014)
101.INS
XBRL Instance Document
101.SCH
XBRL Schema Document
101.CAL
XBRL Calculation Linkbase Document
101.DEF
XBRL Definition Linkbase Document
101.LAB
XBRL Label Linkbase Document
101.PRE
XBRL Presentation Linkbase Document
* Filed herewith.
** Previously filed.
† Exhibit constitutes a management contract or compensatory plan or agreement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date: April 17, 2017
By: /s/ David A. Veltri
DAVID A. VELTRI, Director, President and CEO (Principal Executive and Financial Officer)
Date: April 17, 2017
By: /s/ Thomas R. Bandy
THOMAS R. BANDY, Director
Date: April 17, 2017
By: /s/ Jerry W. Danni
JERRY W. DANNI, Director
Date: April 17, 2017
By: /s/ James B. Fraser
JAMES B. FRASER, Director
Date: April 17, 2017
By: /s/ Leo A. Heath
LEO A. HEATH, Director