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
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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.
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
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
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
and 2018
During the year ended
Revenue. Presented below is a comparison of our oil and natural gas sales,
production quantities and average sales prices for the years ended
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 % 31
The increase in our oil sales of
For the year ended
Oil and Natural Gas Production Costs. Presented below is a comparison of our oil and natural gas production costs for the years endedDecember 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
Depreciation, Depletion and Amortization. Our DD&A rate for the year ended
Impairment of
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the years endedDecember 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
32 Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the years endedDecember 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
During the year ended
During the year ended
We recognized rental and other expense of
During the years ended
Interest expense, net decreased by
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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
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 ) 34
Liquidity and Capital Resources
In our Annual Report on Form 10-K for the year ended
The following table sets forth certain measures about our liquidity as of
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
Our sole source of debt financing was a revolving credit facility with APEG II,
which we repaid in full in
As of
In early
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
In
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.
35 Cash Flows
The following table summarizes our cash flows for the years ended
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
Investing Activities. Cash used in investing activities for the year ended
Financing Activities. Cash used in financing activities for the year ended
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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
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