This discussion includes forward-looking statements. Please refer to Cautionary Statement Regarding Forward-Looking Statementsof this annual report on Form 10-K for important information about these types of statements. Additionally, please refer to the Glossary of Oil and Natural Gas Terms of this annual report on Form 10-K for oil and natural gas industry terminology used herein.





Recent Developments

On March 1, 2020, we acquired all of the issued and outstanding equity interests of New Horizon Resources LLC ("New Horizon"), whose assets include acreage and operated producing properties in North Dakota (the "Properties"). The consideration paid at closing consisted of 59,498 shares of our common stock and $150,000 in cash. The New Horizon Properties consist of approximately 1,300 net acres located primarily in McKenzie and Divide Counties, North Dakota, which are 100% held by production, average a 63% working interest and produced approximately 30 net Boepd (88% oil) for the six-month period ended December 31, 2019.





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Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with 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 annual 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 Natural Gas Reserve Estimates. Our estimates of proved reserves are based on quantities of oil and natural 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 natural 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 Natural Gas Properties. We follow the full cost method in accounting for our oil and natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural 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 natural 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 natural 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 natural 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 natural 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, an impairment is recognized.

Derivative Instruments. We have used derivative instruments, typically costless collars and fixed-rate swaps, to manage price risk underlying our oil and natural 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 natural 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 our Chief Executive Officer and Chief Financial Officer as the representative who is authorized to execute trades.





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Joint Interest Operations. We do not serve as operator for any of our oil and natural 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 recognize revenue in accordance with FASB ASC Topic 606-Revenue from Contracts with Customers, which we adopted effective January 1, 2018, using the modified retrospective approach. See Note 2- Revenue Recognition to the Consolidated Financial Statements herein for more information on our adoption of this new accounting standard.

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.

Warrant Liability. In connection with a private placement of common shares in December 2016, we concurrently sold to the purchasers warrants to purchase 100,000 shares of common stock. The exercise price and the number of shares issuable upon exercise of the warrants is subject to adjustment in the event of any stock dividends and splits, reverse stock splits, recapitalization, reorganization or similar transaction, as described in the warrants. The warrants are also subject to "down-round" anti-dilution in the event we issue additional common stock or common stock equivalents at a price per share less than the exercise price in effect. We have classified the warrants as liabilities due to provisions in the warrant agreement that precluded equity classification, including an option of the holder to receive the calculated fair value of the warrant from the Company in cash in the event of a "Fundamental Transaction," as defined in the warrant agreement. Changes in fair value are reported each period in the consolidated statements of operations.

Preferred Stock. We have excluded our Series A Convertible Preferred Stock from stockholders' equity due to a redemption feature whereby the holders of the preferred stock have the option to redeem their shares in the event of a change of control, which is outside of our control. See Note 12- Preferred Stock to the Consolidated Financial Statements herein for more information related to the Series A Convertible Preferred Stock.

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 annual 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, 2019


                                    and 2018

During the year ended December 31, 2019, we recorded a net loss of $0.6 million as compared to a net loss of $1.0 million for the year ended December 31, 2018. In the following sections we discuss our revenue, operating expenses, and non-operating income for the year ended December 31, 2019 compared to the year ended December 31, 2018.

Revenue. Presented below is a comparison of our oil and natural gas sales, production quantities and average sales prices for the years ended December 31, 2019 and 2018 (dollars in thousands, except average sales prices):





                                                                      Change
                                    2019          2018         Amount        Percent

         Revenue:
         Oil                      $   6,149     $   4,609     $   1,540            33 %
         Gas                            424           930          (506 )         -54 %
         Total                    $   6,573         5,539     $   1,034            19 %

         Production quantities:
         Oil (Bbls)                 110,090        75,003        35,087            47 %
         Gas (Mcfe)                 209,518       286,692       (77,174 )         -27 %
         BOE                        145,010       122,785        22,225            18 %

         Average sales prices:
         Oil (Bbls)               $   55.85     $   61.45     $   (5.60 )          -9 %
         Gas (Mcfe)                    2.03          3.24         (1.21 )         -38 %
         BOE                          45.33         45.11          0.22           0.5 %




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The increase in our oil sales of $1.5 million for the year ended December 31, 2019 resulted from a 47% increase in production quantities, which was partially offset by a 9% decrease in the average sales price received during 2019 compared to 2018. The increase in our production quantities for the year ended December 31, 2019 was primarily attributable to production from the development of our South Texas acreage. During 2019, the average differential between WTI quoted prices for crude oil and the prices we realize for sales in the Williston Basin was approximately $5.06 per barrel. We expect our price differentials relative to WTI to strengthen going forward (with the amount of the differential varying over time) due to additional takeaway capacity opened to eastern Canada and U.S. markets and transportation on rail gradually declining. The market optionality on the crude oil gathering systems allows operators to shift volumes between pipeline and rail markets to optimize price realizations.

For the year ended December 31, 2019, we produced 145,010 BOE, or an average of 397 BOE per day, as compared to 122,785 BOE or 336 BOE per day in 2018. Production for our Williston Basin properties decreased by 3,202 BOE during 2019, which is a 5% reduction compared to 2018. This decrease is primarily due to normal production declines. Production from our Eagle Ford, Buda and Georgetown properties in South Texas increased by 43,241 BOE during 2019, a 106% increase compared to 2018. This increase was attributable to the production from our South Texas drilling activity in late 2018 and during 2019.





Oil and Natural Gas Production Costs. Presented below is a comparison of our oil
and natural gas production costs for the years ended December 31, 2019 and 2018
(dollars in thousands):



                                                                     Change
                                      2019        2018        Amount       Percent

          Lease operating expenses   $ 1,848     $ 1,898     $    (50 )          -3 %
          Production taxes               429         392           37             9 %

          Total                      $ 2,277     $ 2,290     $    (13 )          -1 %

For the year ended December 31, 2019, lease operating expense decreased by $50 thousand or 3%. For the year ended December 31, 2019 due to reduced field activity and a reduction in workover expense. Production taxes increased by $37 thousand or 9% compared to 2018. The increase in production taxes is primarily a result of increased revenue from oil and natural gas sales as a result of the production increases in our South Texas properties.

Depreciation, Depletion and Amortization. Our DD&A rate for the year ended December 31, 2019 was $4.78 per BOE compared to $3.20 per BOE for 2018. 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 Natural Gas Properties. During the years ended December 31, 2019 and 2018, we did not record any impairment charges related to our oil and natural gas properties. Our quarterly reserve reports are prepared based on the first-of-the-month, trailing 12-month average for benchmark oil and natural gas prices adjusted for differentials from posted prices.





General and Administrative Expenses. Presented below is a comparison of our
general and administrative expenses for the years ended December 31, 2019 and
2018 (dollars in thousands):



                                                                              Change
                                         2019           2018          Amount         Percent

Compensation and benefits,
including directors                   $    1,146     $    1,453     $     (307 )           -21 %
Stock-based compensation                      41            636           (595 )           -94 %
Professional fees, insurance and
other                                      3,178          1,540          1,638             106 %
Bad debt expense                              28            374           (346 )           -93 %
Total                                 $    4,393     $    4,003     $      390               9 %

General and administrative expenses increased by $0.4 million, or 9%, for the year ended December 31, 2019 compared to the year ended December 31, 2018. This increase was primarily attributable to an increase of $1.6 million related to professional fees. During 2019, we incurred $1.3 million in incremental legal and accounting fees as a result of the APEG II litigation and the forensic accounting review. We believe the expenditures related to the APEG litigation are substantially behind us and expect a significant reduction in professional fees in 2020. Partially offsetting the increase in professional fees were decreases in compensation and benefits and stock-based compensation as a result of reduced headcount and the lack of the payment of a stock bonus for the year ended December 31, 2019. In addition, bad debt expense decreased $0.3 million. Bad debt expense in 2018 was attributable to the write-off of a deposit for an abandoned acquisition prospect, for which return of the deposit was uncertain, however, during 2019 we recovered $150 thousand of the deposit and as of March 20, 2020 we have received a total of $200 thousand. We have recorded the recovery of the deposit in non-operating income. Bad debt expense in 2019 relates to the write-off of a receivable from a joint interest operator in bankruptcy.





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Non-Operating Income (Expense). Presented below is a comparison of our
non-operating income (expense) for the years ended December 31, 2019 and 2018
(dollars in thousands):



                                                                              Change
                                         2019           2018          Amount          Percent

Realized loss on commodity price
risk derivatives                      $        -     $     (283 )   $       283             100 %
Unrealized gain on commodity price
risk derivatives                               -            161            (161 )           100 %
Recovery of deposit                          200              -             200             100 %
Loss on marketable equity
securities                                  (230 )         (339 )           109             -32 %
Rental and other expense                     (70 )         (114 )            44             -39 %
Gain on warrant revaluation                  351            775            (424 )           -55 %
Interest expense, net                        (11 )          (93 )            82             -88 %
Total other income                    $      240     $      107     $       133             124 %

At December 31, 2019 and 2018 we did not have any outstanding commodity derivative contracts. For the year ended December 31, 2018, we recognized unrealized gains on commodity price risk derivatives of $0.2 million and realized losses of $0.3 million.

During the year ended December 31, 2019, we recognized $0.2 million on the recovery of a transaction deposit for an abandoned acquisition prospect, which was written-off in 2018.

During the year ended December 31, 2019 and 2018, we recognized unrealized losses on marketable equity securities of $0.2 million and $0.3 million, respectively primarily due to a decline in the value of our investment in marketable securities of Anfield Energy.

We recognized rental and other expense of $0.1 million for each of the years ended December 31, 2019 and 2018 related to the operation of our building in Riverton, Wyoming.

During the years ended December 31, 2019 and 2018, we recognized gains on the revaluation of our outstanding warrants of $0.4 million and $0.8 million, respectively, primarily as a result of the decline in value of our common stock.

Interest expense, net decreased by $82 thousand for the year ended December 31, 2019 compared to 2018 due to the repayment of $937 thousand outstanding on the credit agreement in March 2019.





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Non-GAAP Financial Measures - Adjusted EBITDAX

Adjusted EBITDAX represents income (loss) from continuing operations as further modified to eliminate impairments, depreciation, depletion, accretion and amortization, stock-based compensation expense, loss (gain) on marketable equity securities, unrealized derivative (gains) and losses, interest expense, net 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.

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 natural 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.

The following table provides reconciliations of net loss to adjusted EBITDAX for the years ended December 31, 2019 and 2018, in thousands:





                                                             2019        2018

      Net loss (GAAP)                                       $ (550 )   $ (1,040 )
      Depreciation, depletion, accretion and amortization      693          393
      Loss on marketable equity securities                     229          339
      Stock-based compensation expense                          41          636
      Unrealized derivative gain                                 -         (161 )
      Change in fair value of warrants                        (352 )       (775 )
      Interest expense, net                                     11           93
      Adjusted EBITDAX (Non-GAAP)                           $   72     $   (515 )




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Liquidity and Capital Resources

In our Annual Report on Form 10-K for the year ended December 31, 2018 we reported that there was substantial doubt regarding our ability to fund operations for the next twelve months and continue as a going concern. The substantial doubt was primarily related to uncertainty regarding continuing expenditures in the APEG II litigation. Although the litigation remains pending, we believe that the expenditures related to the litigation are substantially behind us. During 2019, we took many steps to preserve liquidity including reducing the use of third-party contractors, cutting corporate overhead and eliminating other general and administrative costs. Additionally, in March 2020, there has been a significant decline in commodity prices. While we expect to experience a decrease in our oil and natural gas revenue, we believe that our existing cash and capital resources and our low overhead has alleviated the substantial doubt regarding our ability to continue as a going concern and we expect we will be able to fund operations for the next twelve months.

The following table sets forth certain measures about our liquidity as of December 31, 2019 and 2018, in thousands:





                                               2019               2018           Change

 Cash and equivalents                     $        1,532     $        2,340     $   (808 )
 Working capital surplus (1)                       1,470              2,018         (548 )
 Total assets                                     13,467             14,778       (1,392 )
 Outstanding debt under credit facility                -                937         (937 )
 Borrowing base under credit facility                  -              6,000       (6,000 )
 Total shareholders' equity                        9,210              9,719         (509 )

 Select Ratios:
 Current ratio (2)                          2.20 to 1.00       2.21 to 1.00
 Debt to equity ratio (3)                            N/A       0.10 to 1.00

(1) Working capital is computed by subtracting total current liabilities from

total current assets.

(2) The current ratio is computed by dividing total current assets by total

current liabilities.

(3) The debt to equity ratio is computed by dividing total debt by total


      shareholders' equity.

As of December 31, 2019, we had a working capital surplus of $1.5 million compared to a working capital surplus of $2.0 million as of December 31, 2018, a decrease of $0.5 million. This decrease was primarily attributable to additional legal and professional expenses as a result of the litigation with APEG II, which was partially offset by an increase in oil and natural gas revenue as a result of production increases in our South Texas properties.

Our sole source of debt financing was a revolving credit facility with APEG II, which we repaid in full in March 2019 and the credit facility matured on July 30, 2019. The borrowing base was $6.0 million as of December 31, 2018. As of December 31, 2018, outstanding borrowings were $0.9 million and we had borrowing availability of $5.1 million. As of December 31, 2018, we were in compliance with all financial covenants associated with the credit facility. APEG II was the secured lender under the credit facility and is currently involved in litigation with us, as described in Item 1. Business-Litigation and Liquidity-APEG II Litigation. As described above, the costs associated with the pending litigation were a significant use of our existing cash during 2019, but we believe the expenditures are significantly behind us.

As of December 31, 2019, we had cash and cash equivalents of $1.5 million and accounts payable and accrued liabilities of $1.0 million. As of March 20, 2020, we had cash and cash equivalents of $1.4 million and accounts payable and accrued liabilities of approximately $0.7 million.. As of March 20, 2020, we have incurred approximately $1.3 million for litigation and the forensic accounting investigation.

In early March 2020, the NYMEX WTI crude oil price decreased significantly. Currently, we do not have any commodity derivative contracts in place to mitigate the effect of lower commodity prices on our revenues. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or gas prices may materially and adversely affect our future business, financial position, cash flows, results of operations, liquidity, ability to finance planned capital expenditures and the oil and natural gas reserves that we can economically produce.

Lower crude prices could also affect the realizability of our oil and gas properties. In the calculation of the ceiling test for the year ended December 31, 2019, we used $55.69 per barrel for oil and $2.58 per mcf for natural gas (as further adjusted for differentials related to property, specific gravity, quality, local markets and distance from markets) to compute the future cash flows of our producing properties. The discount factor used was 10%. As of March 20, 2020, the WTI spot price for crude oil was $23.64 and the 12-month strip price was $28.44. To determine the extent of these price reductions on the realizability of our oil and gas properties, we reran the year end reserves using 50% of the average crude price used in the original ceiling test calculation, or $27.85, as further adjusted for differentials, and determined that by using that price the Company would have incurred a ceiling test write-down of approximately $1.7 million.

In February 2020, we began a process to sell our building and land in Riverton, Wyoming. An independent appraisal prepared as of January 31, 2020, valued the building and land at $3.8 million. We are working with a large national commercial real estate firm to market the property which we expect to begin in the second fiscal quarter of 2020. We cannot be certain that we will be able to complete the sale of the property in 2020 at or near the appraised value, or at all.

If we have needs for financing in 2020, alternatives that we will consider in addition to cash flow from ongoing operations would potentially include refinancing into a new reserve-based credit facility, selling all or a partial interest in our oil and natural gas assets, 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.





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Cash Flows

The following table summarizes our cash flows for the years ended December 31, 2019 and 2018 (in thousands):





                                               2019         2018        Change
           Net cash provided by (used in):
           Operating activities              $    638     $   (490 )   $  1,128
           Investing activities                  (281 )     (1,310 )      1,030
           Financing activities                (1,165 )        863       (2,028 )

Operating Activities. Cash provided by operating activities for the year ended December 31, 2019 was $0.6 million as compared to cash used in operating activities of $0.5 million for 2018, an increase of $1.1 million. This increase was primarily related to the increase in oil revenues as a result of production increases in our South Texas properties.

Investing Activities. Cash used in investing activities for the year ended December 31, 2019 was $0.3 million compared to cash used in investing activities of $1.3 million for 2018, a decrease of $1.0 million. The decrease in cash used in investing activities was primarily attributable to a reduction in capital expenditures for oil and gas properties and the proceeds received from the sale of four wells in South Texas.

Financing Activities. Cash used in financing activities for the year ended December 31, 2019 was $1.2 million as compared to cash provided by financing activities of $0.9 million for 2018, a decrease of $2.1 million. The decrease was due to the $0.9 million repayment of the credit facility and a $0.2 million repayment of a note payable to finance insurance premiums during 2019. In 2018 cash provided by financing activities was primarily due to $1.7 million of proceeds, net of offering costs, from the at-the-market issuances of common stock, which was partially offset by a $0.6 million principal payment on our credit facility.





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Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities ("SPEs"), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist, if it is determined that we are the primary beneficiary of a variable interest entity, that entity will be consolidated in our consolidated financial statements. We have not been involved in any off-balance sheet arrangements via unconsolidated SPE transactions during the two-year period ended December 31, 2019.

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