Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Apr. 16, 2019 | Dec. 29, 2018 | |
Document And Entity Information | |||
Entity Registrant Name | Citadel Exploration, Inc. | ||
Entity Central Index Key | 0001482075 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Is Entity a Well-known Seasoned Issuer? | No | ||
Is Entity a Voluntary Filer? | No | ||
Is Entity's Reporting Status Current? | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $ 6,750,000 | ||
Entity Common Stock, Shares Outstanding | 48,956,147 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2018 | ||
Entity Shell Company | false | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | true | ||
Entity Ex Transition Period | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash | $ 86,441 | $ 772,103 |
Other receivable | 135,824 | 16,540 |
Prepaid expenses | 32,633 | 29,280 |
Product inventory | 20,107 | |
Total current assets | 254,898 | 838,030 |
Deposits | 35,100 | 10,100 |
Restricted cash | 200,000 | 200,000 |
Oil and gas properties, successful efforts basis | ||
Proved, net | 5,685,535 | 5,018,086 |
Unproved | 1,172,034 | 1,170,000 |
Equipment, net | 67,326 | 82,969 |
Total assets | 7,414,893 | 7,319,185 |
Current liabilities: | ||
Accounts payable and accrued payables | 2,657,590 | 2,220,938 |
Accrued interest payable | 390,224 | 459,416 |
Drilling obligation, net of discount of $63,000 and $126,000 as of September 30, 2018 and December 31, 2017 respectively | 676,060 | 700,000 |
Notes payable, net | 2,353,003 | 579,951 |
Related party production payment liability | 300,000 | 300,000 |
Total current liabilities | 6,376,877 | 4,260,305 |
Asset retirement obligation | 250,358 | 224,380 |
Total liabilities | 6,627,235 | 4,484,685 |
Stockholders' equity: | ||
Common stock, $0.001 par value, 300,000,000 shares authorized, 45,000,000 and 44,449,742 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively | 45,000 | 44,450 |
Series A Preferred stock, $20.00 par value, 500,000 shares authorized, 395,615 and 394,365 shares issued and outstanding as of December 31, 2018 and December 31, 2017 respectively | 7,912,300 | 7,887,300 |
Additional paid-in capital | 6,150,871 | 5,691,239 |
Accumulated deficit | (13,320,513) | (10,788,489) |
Total stockholders' equity | 787,658 | 2,834,500 |
Total liabilities and stockholders' equity | $ 7,414,893 | $ 7,319,185 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, issued | 45,000,000 | 44,449,742 |
Common stock, outstanding | 45,000,000 | 44,449,742 |
Preferred stock, par value | $ 20 | $ 20 |
Preferred stock, shares authorized | 500,000 | 500,000 |
Preferred stock, issued | 395,615 | 394,365 |
Preferred stock, outstanding | 395,615 | 394,365 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement [Abstract] | ||
Revenue | $ 1,066,314 | $ 166,355 |
Operating expenses: | ||
Lease operating expense | 822,674 | 232,081 |
General and administrative | 298,889 | 246,764 |
Depreciation, depletion and amortization | 571,301 | 134,619 |
Professional fees | 277,025 | 201,763 |
Executive compensation | 1,216,529 | 651,760 |
Dry hole, abandonment, impairment, and exploration | 427,353 | |
Total operating expenses | 3,186,418 | 1,894,340 |
Other expenses: | ||
Gain on settlement of prior year preferred stock liability | 50,122 | |
Gain - other | 4,000 | |
Interest expense | (411,920) | (79,481) |
Total other expenses | (411,920) | (25,359) |
Loss before provision for income taxes | (2,532,024) | (1,753,344) |
Provision for income taxes | ||
Net loss | (2,532,024) | (1,753,344) |
Series A preferred stock dividends | (791,230) | (620,347) |
Deemed dividend, ORRI issued with preferred stock | (442,136) | |
Net loss available to common stockholders | $ (3,323,254) | $ (2,815,827) |
Weighted average number of common shares - outstanding - basic and diluted | 44,726,467 | 40,891,604 |
Net loss per share - basic and diluted | $ (0.07) | $ (0.07) |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDER EQUITY - USD ($) | Common Stock | Preferred Stock | Additional Paid-In Capital | Accumulated Deficit | Total |
Beginning Balance at Dec. 31, 2016 | $ 39,314 | $ 5,790,060 | $ (9,035,145) | $ (3,205,771) | |
Beginning Balance, Shares at Dec. 31, 2016 | 39,314,004 | ||||
Shares issued for cash | $ 1,175,000 | 1,175,000 | |||
Shares issued for cash, shares | 58,750 | ||||
Shares issued to settle bonus payable | |||||
Preferred shares issued for settlement of notes payable | $ 105,000 | 105,000 | |||
Preferred shares issued for settlement of notes payable, shares | 5,250 | ||||
Preferred shares issued to settle preferred stock payable | $ 6,607,300 | 6,607,300 | |||
Preferred shares issued to settle preferred stock payable, shares | 330,365 | ||||
Common shares issued for special preferred stock dividend | $ 3,102 | (3,102) | |||
Common shares issued for special preferred stock dividend, shares | 3,101,736 | ||||
Common shares issued to settle accrued interest on preferred stock | $ 20,334 | 242,046 | 244,080 | ||
Common shares issued to settle accrued interest on preferred stock, shares | 2,034,002 | ||||
Contribution from related party on preferred stock interest | 104,371 | 104,371 | |||
Deemed dividend, overriding royalty interest issued with preferred stock | (442,136) | (442,136) | |||
Warrants on senior secured facility | |||||
Net loss | (1,753,344) | (1,753,344) | |||
Ending Balance at Dec. 31, 2017 | $ 44,450 | $ 7,887,300 | 5,691,239 | (10,788,489) | 2,834,500 |
Ending Balance, Shares at Dec. 31, 2017 | 44,449,742 | 394,365 | |||
Common shares issued for services rendered | $ 450 | 89,602 | 90,052 | ||
Common shares issued for services rendered, Shares | 450,262 | ||||
Shares issued for cash | $ 25,000 | 25,000 | |||
Shares issued for cash, shares | 1,250 | ||||
Shares issued to settle bonus payable | $ 100 | 19,900 | 20,000 | ||
Shares issued to settle bonus payable, Shares | 100,000 | ||||
Preferred shares issued for settlement of notes payable | |||||
Preferred shares issued to settle preferred stock payable | |||||
Common shares issued to settle accrued interest on preferred stock | |||||
Contribution from related party on preferred stock interest | |||||
Deemed dividend, overriding royalty interest issued with preferred stock | |||||
Warrants on senior secured facility | 225,170 | 225,170 | |||
Stock option expense, related to stock-based compensation issued with executive compensation | 124,960 | 124,960 | |||
Net loss | (2,532,024) | (2,532,024) | |||
Ending Balance at Dec. 31, 2018 | $ 45,000 | $ 7,912,300 | $ 6,150,871 | $ (13,320,513) | $ 787,658 |
Ending Balance, Shares at Dec. 31, 2018 | 45,000,004 | 395,615 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
OPERATING ACTIVITIES | ||
Net loss | $ (2,532,024) | $ (1,753,344) |
Adjustments to reconcile net loss to net cash used in operating activities: | ||
Depreciation, amortization and accretion | 571,301 | 134,619 |
Amortization of debt discount | 248,035 | |
Abandonment and impairment | 427,353 | |
Stock based compensation expense | 215,011 | |
Gain on settlement of prior year preferred stock liability | (50,122) | |
Overriding royalty interest granted as compensation | 430,092 | |
Changes in operating assets and liabilities: | ||
Decrease (increase) in inventory | (191) | |
Decrease (increase) in other receivable | (119,284) | (9,398) |
Decrease (increase) in prepaid expenses | 58,884 | 57,076 |
Increase in deposits | (25,000) | (200) |
Decrease in restricted cash | 45,000 | |
Increase in accrued interest payable | 160,196 | 170,640 |
Increase in accounts payable and accrued | 556,652 | 636,680 |
Net cash used in operating activities | (436,135) | (341,887) |
INVESTING ACTIVITIES | ||
Exploration and development of oil and gas properties | (1,602,400) | (981,622) |
Purchase of equipment | (6,749) | (6,214) |
Net cash used in investing activities | (1,609,149) | (987,876) |
FINANCING ACTIVITIES | ||
Proceeds from sale of preferred stock, net of costs | 25,000 | 1,175,000 |
Proceeds from loans payable | 1,520,612 | 605,000 |
Repayments to drilling liability | (107,940) | 700,000 |
Repayments of notes payable | (78,050) | (566,927) |
Net cash provided by financing activities | 1,359,622 | 1,913,073 |
Net increase in cash and restricted cash | (685,662) | 583,310 |
Cash and restricted cash at beginning of year | 772,103 | 188,793 |
Cash and restricted cash at end of the period | 286,441 | 772,103 |
SUPPLEMENTAL INFORMATION: | ||
Income taxes paid | 2,300 | |
Reclass of inventory to O&G properties | 20,107 | |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||
Preferred shares issued to settle preferred stock payable | 6,607,300 | |
Preferred shares issued to settle note payable | 105,000 | |
Debt Discount from drilling liability | 126,000 | |
Common Stock issued for preferred stock dividend | 3,102 | |
Financing of vehicles | 67,078 | |
Financing of insurance premium | 52,920 | |
Common shares issued to settle accrued interest on preferred stock | 244,080 | |
Deemed dividend, ORRI issued with preferred stock | 442,136 | |
Gain of settlement of prior year preferred stock liability recorded in APIC | 104,371 | |
Debt discount for warrants issued on loans | 225,170 | |
Accrued interest payable rolled over to senior loan facility | 229,388 | |
Asset retirement obligation | 12,128 | |
Insurance premium financing | 62,237 | |
Shares issued to settle bonus payable | 20,000 | |
Non-cash addition of senior loan facility for payment of San Benito litigation | $ 100,000 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | Note 1 – Summary of Significant Accounting Policies Organization Citadel Exploration, Inc. ("Citadel Inc") was incorporated on December 17, 2009 in the State of Nevada originally under the name Subprime Advantage, Inc. On March 2, 2011, the Company changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc. On May 3, 2011, Citadel Inc completed the acquisition of 100% interest in Citadel Exploration, LLC, a California limited liability company, ("Citadel LLC") pursuant to a Membership Purchase Agreement (the "MPA"). Under the MPA, Citadel Inc issued 14,000,000 shares of the its common stock an individual in exchange for a 100% interest in Citadel LLC. Additionally under the MPA, the former officers and directors of Citadel Inc agreed to cancel 7,696,000 shares of its common stock. For accounting purposes, the acquisition of the Citadel LLC by Citadel Inc has been accounted for as a recapitalization, similar to a reverse acquisition except no goodwill is recorded, whereby the private company, Citadel LLC, in substance acquired a non-operational public company (Citadel Inc) with nominal assets and liabilities for the purpose of becoming a public company. Accordingly, Citadel LLC are considered the acquirer for accounting purposes and thus, the historical financials are primarily that of Citadel LLC. As a result of this transaction, Citadel Inc changed its business direction and is now involved in the acquisition and development of oil and gas resources in California. Citadel LLC was incorporated on November 6, 2006 (Date of Inception) and accordingly, the accompanying consolidated financial statements are from the Date of Inception of Citadel LLC through ending reporting periods reflected. The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America applicable to exploration stage enterprises, and are expressed in U.S. dollars. The Company’s fiscal year end is December 31. Principles of consolidation For the years ended December 31, 2018 and 2017, the consolidated financial statements include the accounts of Citadel Exploration, Inc. and Citadel Exploration, LLC. All significant intercompany balances and transactions have been eliminated. Citadel Exploration, Inc. and Citadel Exploration, LLC will be collectively referred herein to as the “Company”. Nature of operations Currently, the Company is focused on the acquisition and development of oil and gas resources in California. Assumptions, Judgments and Estimates In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established. The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Fair value of financial instruments Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2018 and 2017. See Footnote No. 13, “Fair Value of Financial Instruments,” for further information. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, prepaid expenses and accounts payable. Fair values were assumed to approximate carrying values for payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand. Level 1: The preferred inputs to valuation efforts are “quoted prices in active markets for identical assets or liabilities,” with the caveat that the reporting entity must have access to that market. Information at this level is based on direct observations of transactions involving the same assets and liabilities, not assumptions, and thus offers superior reliability. However, relatively few items, especially physical assets, actually trade in active markets. Level 2: FASB acknowledged that active markets for identical assets and liabilities are relatively uncommon and, even when they do exist, they may be too thin to provide reliable information. To deal with this shortage of direct data, the board provided a second level of inputs that can be applied in three situations. Level 3: If inputs from levels 1 and 2 are not available, FASB acknowledges that fair value measures of many assets and liabilities are less precise. The board describes Level 3 inputs as “unobservable,” and limits their use by saying they “shall be used to measure fair value to the extent that observable inputs are not available.” This category allows “for situations in which there is little, if any, market activity for the asset or liability at the measurement date”. Earlier in the standard, FASB explains that “observable inputs” are gathered from sources other than the reporting company and that they are expected to reflect assumptions made by market participants. Inventories Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of cost or market. Oil and Natural Gas Properties The Company accounts for our oil and gas exploration and development costs using the successful efforts method. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive. We review our oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. Property, Plant and Equipment The Company records all property and equipment at cost less accumulated depreciation. Improvements are capitalized while repairs and maintenance costs are expensed as incurred. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Leasehold improvements include the cost of the Company’s internal development and construction department. The Company capitalizes the costs associated with the development of the Company’s website pursuant to ASC Topic 350. Stock-based compensation The Company records stock-based compensation in accordance with the guidance in ASC Topic 505 and 718 which requires the Company to recognize expenses related to the fair value of its employee stock option awards. The Company recognizes the cost of all share-based awards on a graded vesting basis over the vesting period of the award. The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50. Earnings per share The Company follows ASC Topic 260 to account for the earnings per share. Basic earnings per common share (“EPS”) calculations are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share calculations are determined by dividing net income by the weighted average number of common shares and dilutive common share equivalents outstanding. During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation. Cash and cash equivalents The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents. Concentrations of credit risk Financial instruments that subject the Company to credit risk could consist of cash balances maintained in excess of federal depository insurance limits. The Company maintains its cash and cash equivalent balances with high credit quality financial institutions. At times, cash and cash equivalent balances may be in excess of Federal Deposit Insurance Corporation limits. To date, the Company has not experienced any such losses. Restricted cash Restricted cash consisted of a blanket bond totaling $200,000. Bonds are required to meet financial bonding requirements in the state of California. The blanket bond, which will cover 50 wells, was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field. Debt discount The Company records debt discount as a contra liability account and is presented net of the associated loan. The discount is amortized over the life on the loan using the straight-line method because the straight-line method approximates the effective interest method. Revenue Recognition As background, Citadel Exploration has one source of revenue, Phillips 66, the refiner that purchases our crude oil. Citadel receives a check from the purchaser Phillips 66 on the 20 th Performance Obligations: Phillips 66 has been our purchaser for the last two years and has never missed a payment. From a qualitative measure they could not perform any better. Variable Consideration: The price Citadel receives for its oil, is tracked daily by several services including Bloomberg.com, oilprice.com and on Chevron’s webpage. This price is wildly available and transparent. Citadel does not calculate, or control said price. From a quantitative standpoint, we do not have any control. From a qualitative standpoint, we compare what we are paid, versus what prices averaged for the quarter. Recognizing revenue: Citadel is sent an oil ticket summary on or around the 10 th th Costs to obtain a contract: The only cost that Citadel incurs is a transportation cost. The actual contract has no costs. As an example, prior to Phillips 66 we sold to Plains All American (PAA). Our PAA contract charged us $1.95 for transportation. Through various contacts we were introduced to Phillips 66, and they quoted Citadel a transportation cost of $1.45. Both contracts were based on the exact same California heavy oil index for price, therefore the ability to save/realize an additional $0.50 per barrel was the motivation for the change. From a qualitative standpoint, Phillips 66 and PAA are both multibillion-dollar companies. Therefore, we did not see a difference in credit risk to getting paid. Gross versus net presentation: This does not apply as we are paid the gross value of our oil minus transportation costs. We do not accept a discount. Disaggregated revenue: This does not apply as we sell oil from one facility at one oil field and do not have multiple fields or multiple refiners. In conclusion, Citadel’s business and hence revenue is pretty simple and straight forward. We sell one product, to one refiner, and we are paid once a month. Asset Retirement Obligation The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. Revenue & Expense Recognition The Company utilizes accrual basis of accounting when measuring financial position and operating results. The accrual basis recognizes revenues and expenses in the accounting period in which those transactions, events, or circumstances occur (goods or services are received) and become measurable. The Company recognizes its expenses when the expenses are incurred, not necessarily when they are paid. Expenses are generally incurred when the company receives tangible goods or services are provided. Lease operating expense Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Depreciation, Depletion and Amortization The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization —oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased depreciation, depletion and amortization oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields. Income taxes The Company follows ASC Topic 740 for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the consolidated financial statements and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period. If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change. Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. The net operating loss carryforward for the year ended December 31, 2018 is $11,534,488 and the deferred tax asset is $3,595,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,595,000. The Company applies a more-likely-than-not recognition threshold for all tax uncertainties. ASC Topic 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As of December 31, 2018 and 2017, the Company reviewed its tax positions and determined there were no outstanding, or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore this standard has not had a material effect on the Company. The Company does not anticipate any significant changes to its total unrecognized tax benefits within the next 12 months. The Company classifies tax-related penalties and net interest as income tax expense. As of December 31, 2018 and 2017, no income tax expense has been recorded. Long-lived Assets In accordance with the Financial Accounting Standards Board ("FASB") Accounts Standard Codification (ASC) ASC 360-10, "Property, Plant and Equipment," the carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. Proved oil properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil properties and compares these undiscounted cash flows to the carrying amount of the oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. Leases The Company had two types of leases. A capital lease for the financing of vehicles. An operational lease on its steam generator, in which the Company had previously purchased the generator and then sold the generator with an agreement to lease the equipment. Thus, this meets the definition of a sales lease-back arrangement. Since there was no gain or loss from the sale, there is no affect in the income statement. Recent pronouncements In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09) In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. These accounting pronouncements were adopted by the Company as of January 1, 2018. The purpose of Update 2016 -18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of- period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. Adoption of this new standard did not have a material impact on the Company’s financial statements. |
GOING CONCERN
GOING CONCERN | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
GOING CONCERN | Note 2 – Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the recoverability of assets and the satisfaction of liabilities in the normal course of business. As noted above, the Company is in the exploration stage and, accordingly, has not yet generated significant revenues from operations. Since its inception, the Company has been engaged substantially in financing activities and developing its business plan and incurring startup costs and expenses. As a result, the Company incurred a net loss for year ended December 31, 2018 of $2,532,025. In addition, the Company’s exploration activities since inception have been financially sustained through debt and equity financing. These factors raise substantial doubt regarding the Company’s ability to continue as a going concern. These financial statements do not include any adjustments to the recoverability and classification of recorded asset amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern. The ability of the Company to continue as a going concern is dependent upon its ability to raise additional capital from the sale of common stock and, ultimately, the achievement of significant operating revenues. These consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classification of liabilities that might result from this uncertainty. |
RESTRICTED CASH
RESTRICTED CASH | 12 Months Ended |
Dec. 31, 2018 | |
Restricted Cash | |
RESTRICTED CASH | Note 3 – Restricted Cash Restricted cash consists of one bond totaling $200,000 which is a blanket bond that will cover up to 50 wells. This bond was required in the normal course of business in the oil and gas industry. The bond totaling $200,000 was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field. The detail breakdown of restricted cash and cash is depicted in the Consolidated Statement of Cash Flows as follows: |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | Note 4 – Commitments and Contingencies Operating Leases No operating leases for year ended December 31, 2018 Legal Proceedings Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company. The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected areas. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2018. There can be no assurance, however, that the current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties. |
OIL AND GAS PROPERTIES, BUILDIN
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT | Note 5 – Oil and Gas Properties, Buildings, and Equipment Oil and natural gas properties consist of the following: 2018 2017 Oil and Natural Gas: Proved properties $ 4,121,940 $ 3,468,306 Unproved properties 1,172,034 1,170,000 Facilities 2,231,561 2,244,716 7,525, 535 6,883,022 Less oil property impairment (562,030 ) Less accumulated depreciation, depletion, and amortization (667,966 ) (132,906 ) $ 6,857, 569 $ 6,188,086 During the year ended December 31, 2018, the Company spent $1,602,400 to continue to develop the Kern Bluff field and associated facilities. Also, during the year, the Company granted a 2% overriding royalty interest to management which was valued at $430,092. As an annual process, Citadel reviewed the field to determine if asset impairment is required. If the carrying amount of the asset exceeds the sum of the undiscounted estimated future net cash flows, the Company will recognize impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves, utilizing a 10% rate of return. This process includes a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. Citadel cannot predict the amount of impairment charges that may be recorded in the future. During the year ended December 31, 2017, the Company reduced the asset value by $427,353 due to focusing CAPEX at Kern Bluff and idling operations at Yowlumne. During the year ended December 31, 2018, the Company did not have any impairment of assets. Kern Bluff Oil Field The Kern Bluff Oil Field is comprised of approximately 1,100 acres. The field currently has 15 producing wells and an additional 20 idle well bores. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | Note 6 – Income Taxes The (benefit) provision for income taxes from continuing operations consists of the following (in thousands): Year Ended December 31, 2018 2017 Current: Federal $ — $ — State 4 2 4 2 Deferred: Federal — — State — — — — Total $ 4 $ 2 The components of the net deferred income tax liabilities consist of the following: Year Ended December 31, 2018 2017 Deferred income tax assets: Equity and deferred compensation 255 239 Net operating loss 2,442 1,918 State net operating loss carry forward 1,020 808 Other, net — — Total deferred tax assets 3,697 2,965 Valuation allowance (3,211 ) (2,907 ) 486 58 Deferred income tax liabilities: Depreciation and depletion (486 ) (58 ) Net deferred income tax liabilities $ — $ — As of the year ended December 31, 2018, the Company does not have any uncertain tax positions. As of December 31, 2018, we had approximately $11,534,488 in net operating loss carryforwards for each federal and state income tax purposes. The net operating loss carryforward will begin to expire in 20 years if left unused. In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management has concluded that there is no assurance that the company will have taxable income in the future; therefore 100% of the deferred income tax assets is not recognized. On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (AMT), and imposing limitations on the use of net operating losses arising in taxable years beginning after December 31, 2017. Although most of the provisions of the Act are not effective until tax years ending after December 31, 2017, the effects of new legislation are recognized upon enactment in accordance with GAAP. As a result, recognition of the tax effects of the Act is required in the consolidated financial statements for the fiscal year ended December 31, 2017. In accordance with this Act, the Company has calculated its deferred tax asset at December 31, 2017 using the newly enacted corporate tax rate of 21%. We consider the scheduled reversal of deferred tax assets, the level of historical taxable income and tax planning strategies in making the assessment of the realizability of deferred tax assets. We have identified the U.S. federal and California as our "major" tax jurisdiction. With limited exceptions, we remain subject to IRS examination of our income tax returns filed within the last three (3) years, and to California Franchise Tax Board examination of our income tax returns filed within the last four (4) years. |
EQUIPMENT
EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
EQUIPMENT | Note 7 – Equipment Equipment as of December 31, 2018 and 2017 are as follows: 2018 2017 Vehicles $ 83,578 $ 83,578 Website 1,375 1,375 Furniture/Computer Equip 20,380 20,380 Material/Pipe Supplies 6,750 0 Less: Accumulated depreciation (44,758 ) (22,364 ) $ 67,325 $ 18,530 Two vehicles were purchased during the year ended December 31, 2017 totaling $73,292. Of this amount, $67,078 was financed and $6,214 was paid in cash. Depreciation expense for the years ended December 31, 2018 and 2017, respectively, was $22,392 and $8,854. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
DEBT | Note 8 – Debt Loan payable Notes payable consists of the following: December December Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019 $ 13,939 $ 14,548 Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022 25,598 32,351 Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022 26,390 33,052 Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively 2,350,000 500,000 Unamortized debt discount (62,924 ) — Notes Payable/Senior Secured Credit Facility – Total $ 2,353,003 $ 579,951 During the 2018 period, the Company received proceeds of $2,350,000 in the form of a senior secured credit facility. The senior secured credit facility carries a 10% interest rate and also includes one five-year warrant at $0.10 per share for every two dollars outstanding. As of March 31 st Drilling Obligation The Company entered into a drilling Joint Venture agreement with investors to drill two exploration wells in 2017. The $700,000 drilling liability has an 18% rate of return due to the investor and as such, the Company booked a discount of $126,000 of which $84,000 has been amortized during the year ended December 31, 2018, leaving a balance at December 31, 2018 of $42,000. The discount is being amortized over 18 months. The term is an estimate based on when management expects this liability to be fully settled. |
PRODUCTION PAYMENT LIABIITY
PRODUCTION PAYMENT LIABIITY | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Production Payment Liability | Note 9 – Production Payment Liability In December 2014, the Company entered into a financing agreement with two related party entities. The Company received $300,000 in total from both entities to fund costs of the Yowlumne 2-26 well recompletion. In return for the funds received, the two entities will receive a combined 75% of the net revenue from the well until the $300,000 is repaid. At the time of repayment, the entities will own a total 3% overriding royalty on the well. This liability is completely dependent on the well generating revenue. If the well fails to generate enough revenue to repay the $300,000, Citadel is not responsible for the unpaid amount. According to ASC 932-470-25 Section B, Funds advanced to an operator that are repayable in cash out of the proceeds from a specified share of future production of a producing property, until the amount advanced $300,000 is paid in full, shall be accounted for as a borrowing. The advance is a payable for the recipient of the cash invested. Given the well is not currently on production coupled with the high cost of water disposal, we believe it will take more than two years for payback to occur; therefore this has been classified as a long-term payable. |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Asset Retirement Obligations (AROs) | Note 10 – Asset Retirement Obligations (AROs) The Company's ARO relates to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. In periods subsequent to the initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The increases in the ARO liability due to the passage of time impact net earnings as accretion expense. The related capital cost, including revisions thereto, is charged to expense through depreciation, depletion and amortization of oil and natural gas production over the life of the oil and natural gas field. The following table summarizes the activity for the Company's abandonment obligations: Year Ended December 31, 2018 2017 Beginning balance at January 1 $ 224,380 $ 217,212 Liabilities incurred from property acquisition 12,129 — Accretion expense 13,848 7,168 Ending balance at December 31 $ 250,357 $ 224,380 |
STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
STOCKHOLDERS' EQUITY | Note 11 – Stockholders’ Equity The Company is authorized to issue 300,000,000 shares of its $0.001 par value common stock. In March of 2016, the Company approved the sale of up to 500,000 shares of Series A Convertible Participating Preferred Stock. The following are terms of the Series A Convertible Participating Preferred Stock: 1. Series A – Senior to Common Stock 2. Three-Year Term – Series a Convertible at any time at the holder’s discretion, during the three year-term. Issuer, Citadel Exploration, Inc., can only force convert Series A, if the company’s common stock trades at $1.00 or more for 90 consecutive days. 3. Convertible into Citadel Exploration, Inc. common stock at a term of 1 share of preferred par value $20.00 to 100 shares of Common Stock par value $0.001 – implied conversion rate of $0.20 per share. 4. 10% Coupon, $2.00 per share, paid in semi-annual installments at $1.00 per share and payable in cash or payment in kind of additional Series A Convertible Participating Preferred Stock during first year. 5. 2% Over Riding Royalty Interest (ORRI) on the Kern Bluff Oil Field until conversion into common stock. Upon conversion, ORRI will be reduced to 1% in perpetuity. 6. Royalty to be paid on a quarterly basis, starting at 90 days after the close of the offering. 7. There is no redemption right by the company or the shares holders The Company sold 175,000 shares of Series A Convertible Participating Preferred Stock to convert its $3,500,000 related party note payable to preferred stock. In addition, the Company has sold 21,250 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $425,000 through March 31, 2016. A 2% overriding royalty interest was issued in conjunction with the Series A Convertible Participating Preferred Stock. That value of $442,136 reduces the Company’s proved property valuation. In June of 2016, the Company sold 50,000 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $1,000,000. In September of 2016, the Company sold 26,500 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $530,000. The Company issued 500,000 shares of common stock for cash in the amount of $100,000. In October of 2016, the Company sold 10,350 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $207,000. In November of 2016, the Company sold 29,330 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $586,600. In December of 2016, the Company sold 13,300 shares of Series A Convertible Participating Preferred Stock for cash in the amount of $266,000. As detailed above in the related 2016 issuances, the Company issued 330,365 shares of Series A Convertible Participating Preferred stock to settle the 2016 preferred stock payable in the amount of 6,607,300. These shares were sold in 2016, but issued in 2017. In March of 2017, the Company sold 10,000 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $200,000. In March of 2017, the Company issued 2,034,002 common shares as a special dividend to Series A Preferred Shareholders to settle accrued interest on preferred stock during the 2016 offering period of the Series A totaling $244,080. A gain occurred on the issuance which totaled $50,122. In June of 2017, the Company sold 13,750 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $275,000. In September of 2017, the Company sold 22,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $450,000. In October of 2017, the Company issued 5,250 shares of Series A Convertible Participating Preferred Stock as payment to settle note payable in the amount of $105,000. In December of 2017, the Company sold 12,500 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $250,000. In December of 2017, the Company issued 3,101,736 shares of common stock as payment for dividend on the Series A Preferred Stock during 2017. In December of 2017, the Company adopted the 2017 Restricted Stock Unit Plan (RSU) authorizing the issuance of 10,000,000 restricted stock units to management and future employees. In January of 2018, the Company sold 1,250 shares of Series A Convertible Participating Preferred Stock payable in cash in the amount of $25,000. In January of 2019, the Company issued 3,956,147 shares of common stock as payment for dividend on the Series A Preferred Stock during 2018. |
STOCK OPTION PLAN
STOCK OPTION PLAN | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
STOCK OPTION PLAN | On August 1, 2018 as approved by the Board of Directors, the Company granted 500,000 stock options to three members of the Board of Directors. These options vest over a three year period, at $0.15 per share for a term of seven years. using the Black Scholes option pricing model with an expected life of 7 years, risk free interest rate of 1.872%, dividend yield of 0%, and expected volatility of 333%. The following is a summary of the status of all of the Company’s stock options as of December 31, 2018 and changes during the period ended on that date: Number Weighted-Average Aggregate Intrinsic Value Weighted-Average Remaining Life (Years) Outstanding at January 1, 2017 9,500,000 $ 0.20 $ — 3.26 Exercisable at January 1, 2017 9,500,000 $ 0.20 $ — 3.26 Granted $ 0.00 $ — — Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2017 9,500,000 $ 0.20 $ — 3.26 Exercisable at December 31, 2017 9,500,000 $ 0.20 $ — 3.26 Granted 500,000 $ 0.20 $ — 2.48 Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2018 10,000,000 $ 0.20 $ — 2.48 Exercisable at December 31, 2018 10,000,000 $ 0.20 $ 235,000 2.48 |
WARRANTS
WARRANTS | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
WARRANTS | Note 13 – Warrants In March 2018, the Company closed on a $3,000,000 Senior Secured Credit Facility with $1,750,000 drawn. As per the terms of the agreement, the investors receive one warrant for every two dollars invested. As such the Company issued 875,000 warrants at $0.10 per share with a five-year term. The Company closed on an additional $500,000 of debt in August of 2018 and $100,000 of debt in October 2018 as such the Company issued 250,000 warrants and 50,000 warrants all at the same price and duration as the original tranche. These warrants were fair valued using the Black-Sholes method with an assumption of an average volatility rate of 253%. The relative fair value was recognized as debt discount The following is a summary of the status of the Company’s stock warrants as of December 31, 2018 and changes during the period ended on that date: Number Weighted-Average Exercise Price Weighted-Average Remaining Life (Years) Outstanding at January 1, 2017 — $ 0.00 — Granted 875,000 $ 0.20 4.21 Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at March 31, 2018 875,000 $ 0.20 4.21 Exercisable at March 31, 2018 875,000 $ 0.20 4.21 Granted 250,000 $ 0.20 4.73 Exercised — $ 0.00 — Cancelled — $ 0.00 — Forfeited — $ 0.00 — Outstanding at September 30, 2018 1,125,000 $ 0.20 4.32 Exercisable at September 30, 2018 1,125,000 $ 0.20 4.32 Granted 50,000 $ 0.20 4.79 Exercised — $ 0.00 — Outstanding at December 31, 2018 1,175,000 $ 0.20 4.34 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
RELATED PARTY TRANSACTIONS | Note 14 – Related Party Transactions In December 2014, the Company entered into an agreement with Jim Walesa and Cibolo Creek Partners to fund $300,000 towards the Yowlumne #2-26 recompletion. In this agreement Mr. Walesa and Cibolo Creek will receive 75% of the net revenue after expenses, until they have received $300,000 in payment. Upon full repayment, Mr. Walesa and Cibolo Creek will receive a 3% royalty on the well. Mr. Walesa is currently on the Board of Directors of Citadel and a member of Cibolo Creek Partners. During the year ended December 31, 2018 and December 31, 2017, Jim Walesa and Cibolo Creek Partners invested a total of $0 and $630,000 into the Company’s Series A Preferred Shares. During 2017, the Company has issued Jim Walesa and Cibolo Creek Partners a total of 2,413,867 shares in common stock. During the year ended December 31, 2018 and December 31, 2017, the Company made the following purchases in the amount of $125,217 and $71,328, respectively, from an entity considered a related party for oil field equipment and services from Grey Energy. Grey Energy is owned by James Borgna, who is a member of our Board of Directors. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | Note 15 – Subsequent Events On April 15 th |
SUPPLEMENTAL DISCLOSURE OF OIL
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited) | Note 16 - Supplemental Information about Oil & Natural Gas Producing Activities (Unaudited) The Company’s oil and natural gas reserves are attributable solely to properties within the United States. Capitalized Costs December 31, 2018 2017 Oil and natural gas properties: (in thousands) Proved properties $ 4,513 $ 3,513 Unproved properties 1,172 1,170 Facilities 2,415 2,200 Total oil and natural gas properties 8,100 6,883 Less oil property impairment (562 ) (562 ) Less accumulated depreciation, depletion and amortization (668 ) (133 ) Net oil and natural gas properties capitalized $ 6,870 $ 6,188 Costs Incurred for Oil and Natural Gas Producing Activities Year Ended December 31, 2018 2017 2016 Acquisition costs: (in thousands) Proved properties $ — $ — $ — Unproved properties — — — Development costs 2,211 344 2,171 Total $ 2,211 $ 344 $ 2,171 Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2018, which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2018 was based on an unweighted average 12-month average WTI posted price per Bbl for oil as set forth in the following table: Year Ended December 31, 2018 2017 2016 Oil (per Bbl) $ 65.01 $ 45.94 $ 45.53 Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil reserves are located in the United States in the San Joaquin Valley of California. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table provides a roll forward of the total proved reserves for the years ended December 31, 2018, 2017, and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Year Ended December 31, 2018 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,234 — 1,234 Extensions and discoveries — — — Revisions of previous estimates 55 — 55 Purchases of reserves in place — Divestures of reserves in place — — — Production (17 ) — (17 ) End of the year 1,272 — 1,272 Proved Developed Reserves: Beginning of the year 282 — 282 End of the year 254 — 254 Proved Undeveloped Reserves: Beginning of the year 952 — 952 End of the year 1,018 — 1,018 Year Ended December 31, 2017 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,160 — 1,160 Extensions and discoveries — — — Revisions of previous estimates 78 — 78 Purchases of reserves in place — Divestures of reserves in place — — — Production (4 ) — (4 ) End of the year 1,234 — 1,234 Proved Developed Reserves: Beginning of the year 240 — 240 End of the year 282 — 282 Proved Undeveloped Reserves: Beginning of the year 920 — 920 End of the year 952 — 952 Year Ended December 31, 2016 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,414 — 1,414 Extensions and discoveries — — — Revisions of previous estimates (251 ) — (251 ) Purchases of reserves in place — Divestures of reserves in place — — — Production (3 ) — (3 ) End of the year 1,160 — 1,160 Proved Developed Reserves: Beginning of the year 358 — 358 End of the year 240 — 240 Proved Undeveloped Reserves: Beginning of the year 1,056 — 1,056 End of the year 920 — 920 Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2018, 2017, and 2016 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows: December 31, 2018 2017 2016 (in thousands) Future cash inflows $ 82,708 $ 56,674 $ 41,220 Future development costs (9,575 ) (9,350 ) (8,785 ) Future production costs (36,289 ) (29,232 ) (25,567 ) Future income tax expenses (5,476 ) (1,521 ) (860 ) Future net cash flows 31,386 16,571 6,008 10% discount to reflect timing of cash flows (14,033 ) (6,871 ) (2,927 ) Standardized measure of discounted future net cash flows $ 17,335 $ 3,081 $ 7,107 In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2018, 2017, and 2016, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to income tax deductions, credits, NOL’s and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%. It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the year $ 9,700 $ 3,081 $ 7,107 Sales of oil and natural gas, net of production costs (271 ) (66 ) (5 ) Purchase of minerals in place — — — Divestiture of minerals in place — — — Extensions and discoveries, net of future development costs — — — Previously estimated development costs incurred during the period 1,559 334 — Net changes in prices and production costs 8,839 4,826 8,927 Changes in estimated future development costs (121 ) (324 ) 4,356 Revisions of previous quantity estimates 1,329 (1,896 ) (21,886) Accretion of discount 970 267 420 Net change in income taxes (2,122 ) 314 2,114 Net changes in timing of production and other (2,548 ) — 2,048 Standardized measure of discounted future net cash flows at the end of the year $ 17,335 $ 9,700 $ 3,081 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Basis of presentation | Organization Citadel Exploration, Inc. ("Citadel Inc") was incorporated on December 17, 2009 in the State of Nevada originally under the name Subprime Advantage, Inc. On March 2, 2011, the Company changed its name from Subprime Advantage, Inc. to Citadel Exploration, Inc. On May 3, 2011, Citadel Inc completed the acquisition of 100% interest in Citadel Exploration, LLC, a California limited liability company, ("Citadel LLC") pursuant to a Membership Purchase Agreement (the "MPA"). Under the MPA, Citadel Inc issued 14,000,000 shares of the its common stock an individual in exchange for a 100% interest in Citadel LLC. Additionally under the MPA, the former officers and directors of Citadel Inc agreed to cancel 7,696,000 shares of its common stock. For accounting purposes, the acquisition of the Citadel LLC by Citadel Inc has been accounted for as a recapitalization, similar to a reverse acquisition except no goodwill is recorded, whereby the private company, Citadel LLC, in substance acquired a non-operational public company (Citadel Inc) with nominal assets and liabilities for the purpose of becoming a public company. Accordingly, Citadel LLC are considered the acquirer for accounting purposes and thus, the historical financials are primarily that of Citadel LLC. As a result of this transaction, Citadel Inc changed its business direction and is now involved in the acquisition and development of oil and gas resources in California. Citadel LLC was incorporated on November 6, 2006 (Date of Inception) and accordingly, the accompanying consolidated financial statements are from the Date of Inception of Citadel LLC through ending reporting periods reflected. The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America applicable to exploration stage enterprises, and are expressed in U.S. dollars. The Company’s fiscal year end is December 31. |
Principles of consolidation | Principles of consolidation For the years ended December 31, 2018 and 2017, the consolidated financial statements include the accounts of Citadel Exploration, Inc. and Citadel Exploration, LLC. All significant intercompany balances and transactions have been eliminated. Citadel Exploration, Inc. and Citadel Exploration, LLC will be collectively referred herein to as the “Company”. |
Nature of operations | Nature of operations Currently, the Company is focused on the acquisition and development of oil and gas resources in California. |
Assumptions, Judgments and Estimates | Assumptions, Judgments and Estimates In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established. The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. |
Fair value of financial instruments | Fair value of financial instruments Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2018 and 2017. See Footnote No. 13, “Fair Value of Financial Instruments,” for further information. The respective carrying value of certain on-balance-sheet financial instruments approximated their fair values. These financial instruments include cash, prepaid expenses and accounts payable. Fair values were assumed to approximate carrying values for payables because they are short term in nature and their carrying amounts approximate fair values or they are payable on demand. Level 1: The preferred inputs to valuation efforts are “quoted prices in active markets for identical assets or liabilities,” with the caveat that the reporting entity must have access to that market. Information at this level is based on direct observations of transactions involving the same assets and liabilities, not assumptions, and thus offers superior reliability. However, relatively few items, especially physical assets, actually trade in active markets. Level 2: FASB acknowledged that active markets for identical assets and liabilities are relatively uncommon and, even when they do exist, they may be too thin to provide reliable information. To deal with this shortage of direct data, the board provided a second level of inputs that can be applied in three situations. Level 3: If inputs from levels 1 and 2 are not available, FASB acknowledges that fair value measures of many assets and liabilities are less precise. The board describes Level 3 inputs as “unobservable,” and limits their use by saying they “shall be used to measure fair value to the extent that observable inputs are not available.” This category allows “for situations in which there is little, if any, market activity for the asset or liability at the measurement date”. Earlier in the standard, FASB explains that “observable inputs” are gathered from sources other than the reporting company and that they are expected to reflect assumptions made by market participants. |
Inventories | Inventories Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of cost or market. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company accounts for our oil and gas exploration and development costs using the successful efforts method. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive. We review our oil and natural gas producing properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs which are based upon estimates, the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. |
Property, Plant and Equipment | Property, Plant and Equipment The Company records all property and equipment at cost less accumulated depreciation. Improvements are capitalized while repairs and maintenance costs are expensed as incurred. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Leasehold improvements include the cost of the Company’s internal development and construction department. The Company capitalizes the costs associated with the development of the Company’s website pursuant to ASC Topic 350. |
Stock-based compensation | Stock-based compensation The Company records stock-based compensation in accordance with the guidance in ASC Topic 505 and 718 which requires the Company to recognize expenses related to the fair value of its employee stock option awards. The Company recognizes the cost of all share-based awards on a graded vesting basis over the vesting period of the award. The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50. |
Earnings per share | Earnings per share The Company follows ASC Topic 260 to account for the earnings per share. Basic earnings per common share (“EPS”) calculations are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share calculations are determined by dividing net income by the weighted average number of common shares and dilutive common share equivalents outstanding. During periods when common stock equivalents, if any, are anti-dilutive they are not considered in the computation. |
Cash and Cash Equivalents | Cash and cash equivalents The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents. |
Concentrations of credit risk | Concentrations of credit risk Financial instruments that subject the Company to credit risk could consist of cash balances maintained in excess of federal depository insurance limits. The Company maintains its cash and cash equivalent balances with high credit quality financial institutions. At times, cash and cash equivalent balances may be in excess of Federal Deposit Insurance Corporation limits. To date, the Company has not experienced any such losses. |
Restricted Cash | Restricted cash Restricted cash consisted of a blanket bond totaling $200,000. Bonds are required to meet financial bonding requirements in the state of California. The blanket bond, which will cover 50 wells, was purchased in August 2015 following the acquisition of the Kern Bluff Oil Field. |
Debt discount | Debt discount The Company records debt discount as a contra liability account and is presented net of the associated loan. The discount is amortized over the life on the loan using the straight-line method because the straight-line method approximates the effective interest method. |
Revenue recognition | Revenue Recognition As background, Citadel Exploration has one source of revenue, Phillips 66, the refiner that purchases our crude oil. Citadel receives a check from the purchaser Phillips 66 on the 20 th Performance Obligations: Phillips 66 has been our purchaser for the last two years and has never missed a payment. From a qualitative measure they could not perform any better. Variable Consideration: The price Citadel receives for its oil, is tracked daily by several services including Bloomberg.com, oilprice.com and on Chevron’s webpage. This price is wildly available and transparent. Citadel does not calculate, or control said price. From a quantitative standpoint, we do not have any control. From a qualitative standpoint, we compare what we are paid, versus what prices averaged for the quarter. Recognizing revenue: Citadel is sent an oil ticket summary on or around the 10 th th Costs to obtain a contract: The only cost that Citadel incurs is a transportation cost. The actual contract has no costs. As an example, prior to Phillips 66 we sold to Plains All American (PAA). Our PAA contract charged us $1.95 for transportation. Through various contacts we were introduced to Phillips 66, and they quoted Citadel a transportation cost of $1.45. Both contracts were based on the exact same California heavy oil index for price, therefore the ability to save/realize an additional $0.50 per barrel was the motivation for the change. From a qualitative standpoint, Phillips 66 and PAA are both multibillion-dollar companies. Therefore, we did not see a difference in credit risk to getting paid. Gross versus net presentation: This does not apply as we are paid the gross value of our oil minus transportation costs. We do not accept a discount. Disaggregated revenue: This does not apply as we sell oil from one facility at one oil field and do not have multiple fields or multiple refiners. In conclusion, Citadel’s business and hence revenue is pretty simple and straight forward. We sell one product, to one refiner, and we are paid once a month. |
Asset retirement obligation | Asset Retirement Obligation The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. |
Revenue & Expense Recognition | Revenue & Expense Recognition The Company utilizes accrual basis of accounting when measuring financial position and operating results. The accrual basis recognizes revenues and expenses in the accounting period in which those transactions, events, or circumstances occur (goods or services are received) and become measurable. The Company recognizes its expenses when the expenses are incurred, not necessarily when they are paid. Expenses are generally incurred when the company receives tangible goods or services are provided. |
Lease operating expense | Lease operating expense Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. |
Depreciation, Depletion and Amortization | Depreciation, Depletion and Amortization The provision for DD&A-oil and natural gas production is calculated on a field-by-field basis using the unit-of-production method. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices, may significantly impact estimated reserve quantities. Depreciation, depletion and amortization —oil and natural gas production is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased depreciation, depletion and amortization oil and natural gas production, which in turn reduces net earnings. Changes in reserve estimates are applied on a prospective basis. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher costs fields. |
Income taxes | Income taxes The Company follows ASC Topic 740 for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the consolidated financial statements and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period. If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change. Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse. The net operating loss carryforward for the year ended December 31, 2018 is $11,534,488 and the deferred tax asset is $3,595,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,595,000. The Company applies a more-likely-than-not recognition threshold for all tax uncertainties. ASC Topic 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. As of December 31, 2018 and 2017, the Company reviewed its tax positions and determined there were no outstanding, or retroactive tax positions with less than a 50% likelihood of being sustained upon examination by the taxing authorities, therefore this standard has not had a material effect on the Company. The Company does not anticipate any significant changes to its total unrecognized tax benefits within the next 12 months. The Company classifies tax-related penalties and net interest as income tax expense. As of December 31, 2018 and 2017, no income tax expense has been recorded. |
Long-lived Assets | Long-lived Assets In accordance with the Financial Accounting Standards Board ("FASB") Accounts Standard Codification (ASC) ASC 360-10, "Property, Plant and Equipment," the carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. Proved oil properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil properties and compares these undiscounted cash flows to the carrying amount of the oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. |
Leases | Leases The Company had two types of leases. A capital lease for the financing of vehicles. An operational lease on its steam generator, in which the Company had previously purchased the generator and then sold the generator with an agreement to lease the equipment. Thus, this meets the definition of a sales lease-back arrangement. Since there was no gain or loss from the sale, there is no affect in the income statement. |
Recent pronouncements | Recent pronouncements In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09) In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. These accounting pronouncements were adopted by the Company as of January 1, 2018. The purpose of Update 2016 -18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of- period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. Adoption of this new standard did not have a material impact on the Company’s financial statements. |
OIL AND GAS PROPERTIES, BUILD_2
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Schedule of Oil and natural gas properties, buildings and equipment | Oil and natural gas properties consist of the following: 2018 2017 Oil and Natural Gas: Proved properties $ 4,121,940 $ 3,468,306 Unproved properties 1,172,034 1,170,000 Facilities 2,231,561 2,244,716 7,525, 535 6,883,022 Less oil property impairment (562,030 ) Less accumulated depreciation, depletion, and amortization (667,966 ) (132,906 ) $ 6,857, 569 $ 6,188,086 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of provision for income taxes | The (benefit) provision for income taxes from continuing operations consists of the following (in thousands): Year Ended December 31, 2018 2017 Current: Federal $ — $ — State 4 2 4 2 Deferred: Federal — — State — — — — Total $ 4 $ 2 |
Schedule of Deferred Income Tax Liabilities | The components of the net deferred income tax liabilities consist of the following: Year Ended December 31, 2018 2017 Deferred income tax assets: Equity and deferred compensation 255 239 Net operating loss 2,442 1,918 State net operating loss carry forward 1,080 808 Other, net — — Total deferred tax assets 3,697 2,965 Valuation allowance (3,211 ) (2,907 ) 486 58 Deferred income tax liabilities: Depreciation and depletion (486 ) (58 ) Net deferred income tax liabilities $ — $ — |
EQUIPMENT (Tables)
EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Equipment | Equipment as of December 31, 2018 and 2017 are as follows: 2018 2017 Vehicles $ 83,578 $ 83,578 Website 1,375 1,375 Furniture/Computer Equip 20,380 20,380 Material/Pipe Supplies 6,750 0 Less: Accumulated depreciation (44,758 ) (22,364 ) $ 67,325 $ 18,530 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Schedule of Notes Payable | Notes payable consists of the following: December December Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019 $ 13,939 $ 14,548 Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022 25,598 32,351 Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022 26,390 33,052 Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively 2,350,000 500,000 Unamortized debt discount (62,924 ) — Notes Payable/Senior Secured Credit Facility – Total $ 2,353,003 $ 579,951 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Company announced its first oil production | The following table summarizes the activity for the Company's abandonment obligations: Year Ended December 31, 2018 2017 Beginning balance at January 1 $ 224,380 $ 217,212 Liabilities incurred from property acquisition 12,129 — Accretion expense 13,848 7,168 Ending balance at December 31 $ 250,357 $ 224,380 |
STOCK OPTION PLAN (Tables)
STOCK OPTION PLAN (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Schedule of Company's stock options | The following is a summary of the status of all of the Company’s stock options as of December 31, 2018 and changes during the period ended on that date: Number Weighted-Average Aggregate Intrinsic Value Weighted-Average Remaining Life (Years) Outstanding at January 1, 2017 9,500,000 $ 0.20 $ — 3.26 Exercisable at January 1, 2017 9,500,000 $ 0.20 $ — 3.26 Granted $ 0.00 $ — — Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2017 9,500,000 $ 0.20 $ — 3.26 Exercisable at December 31, 2017 9,500,000 $ 0.20 $ — 3.26 Granted 500,000 $ 0.20 $ — 2.48 Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2018 10,000,000 $ 0.20 $ — 2.48 Exercisable at December 31, 2018 10,000,000 $ 0.20 $ 235,000 2.48 |
WARRANTS (Tables)
WARRANTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Schedule of Warrants | The following is a summary of the status of the Company’s stock warrants as of December 31, 2018 and changes during the period ended on that date: Number Weighted-Average Exercise Price Weighted-Average Remaining Life (Years) Outstanding at January 1, 2017 — $ 0.00 — Granted 875,000 $ 0.20 4.21 Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at March 31, 2018 875,000 $ 0.20 4.21 Exercisable at March 31, 2018 875,000 $ 0.20 4.21 Granted 250,000 $ 0.20 4.73 Exercised — $ 0.00 — Cancelled — $ 0.00 — Forfeited — $ 0.00 — Outstanding at September 30, 2018 1,125,000 $ 0.20 4.32 Exercisable at September 30, 2018 1,125,000 $ 0.20 4.32 Granted 50,000 $ 0.20 4.79 Exercised — $ 0.00 — Outstanding at December 31, 2018 1,175,000 $ 0.20 4.34 |
SUPPLEMENTAL DISCLOSURE OF OI_2
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes to Financial Statements | |
Schedule of Oil and Natural Gas Reserves that are Attributable | Capitalized Costs December 31, 2018 2017 Oil and natural gas properties: (in thousands) Proved properties $ 4,513 $ 3,513 Unproved properties 1,172 1,170 Facilities 2,415 2,200 Total oil and natural gas properties 8,100 6,883 Less oil property impairment (562 ) (562 ) Less accumulated depreciation, depletion and amortization (668 ) (133 ) Net oil and natural gas properties capitalized $ 6,870 $ 6,188 Costs Incurred for Oil and Natural Gas Producing Activities Year Ended December 31, 2018 2017 2016 Acquisition costs: (in thousands) Proved properties $ — $ — $ — Unproved properties — — — Development costs 2,211 344 2,171 Total $ 2,211 $ 344 $ 2,171 |
Schedule of Reserve Quantity Information | The pricing that was used for estimates of the Company’s reserves as of December 31, 2018 was based on an unweighted average 12-month average WTI posted price per Bbl for oil as set forth in the following table: Year Ended December 31, 2018 2017 2016 Oil (per Bbl) $ 65.01 $ 45.94 $ 45.53 |
Schedule of Proved Developed and Undeveloped Reserves | The following table provides a roll forward of the total proved reserves for the years ended December 31, 2018, 2017, and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Year Ended December 31, 2018 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,234 — 1,234 Extensions and discoveries — — — Revisions of previous estimates 55 — 55 Purchases of reserves in place — Divestures of reserves in place — — — Production (17 ) — (17 ) End of the year 1,272 — 1,272 Proved Developed Reserves: Beginning of the year 282 — 282 End of the year 254 — 254 Proved Undeveloped Reserves: Beginning of the year 952 — 952 End of the year 1,018 — 1,018 Year Ended December 31, 2017 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,160 — 1,160 Extensions and discoveries — — — Revisions of previous estimates 78 — 78 Purchases of reserves in place — Divestures of reserves in place — — — Production (4 ) — (4 ) End of the year 1,234 — 1,234 Proved Developed Reserves: Beginning of the year 240 — 240 End of the year 282 — 282 Proved Undeveloped Reserves: Beginning of the year 920 — 920 End of the year 952 — 952 Year Ended December 31, 2016 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) Proved Developed and Undeveloped Reserves: Beginning of the year 1,414 — 1,414 Extensions and discoveries — — — Revisions of previous estimates (251 ) — (251 ) Purchases of reserves in place — Divestures of reserves in place — — — Production (3 ) — (3 ) End of the year 1,160 — 1,160 Proved Developed Reserves: Beginning of the year 358 — 358 End of the year 240 — 240 Proved Undeveloped Reserves: Beginning of the year 1,056 — 1,056 End of the year 920 — 920 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows: December 31, 2018 2017 2016 (in thousands) Future cash inflows $ 82,708 $ 56,674 $ 41,220 Future development costs (9,575 ) (9,350 ) (8,785 ) Future production costs (36,289 ) (29,232 ) (25,567 ) Future income tax expenses (5,476 ) (1,521 ) (860 ) Future net cash flows 31,386 16,571 6,008 10% discount to reflect timing of cash flows (14,033 ) (6,871 ) (2,927 ) Standardized measure of discounted future net cash flows $ 17,335 $ 3,081 $ 7,107 Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the year $ 9,700 $ 3,081 $ 7,107 Sales of oil and natural gas, net of production costs (271 ) (66 ) (5 ) Purchase of minerals in place — — — Divestiture of minerals in place — — — Extensions and discoveries, net of future development costs — — — Previously estimated development costs incurred during the period 1,559 334 — Net changes in prices and production costs 8,839 4,826 8,927 Changes in estimated future development costs (121 ) (324 ) 4,356 Revisions of previous quantity estimates 1,329 (1,896 ) (21,886) Accretion of discount 970 267 420 Net change in income taxes (2,122 ) 314 2,114 Net changes in timing of production and other (2,548 ) — 2,048 Standardized measure of discounted future net cash flows at the end of the year $ 17,335 $ 9,700 $ 3,081 |
RESTRICTED CASH (Details Narrat
RESTRICTED CASH (Details Narrative) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Aug. 25, 2015 |
Disclosure Restricted Cash Details Narrative Abstract | |||
Restricted Cash | $ 200,000 | $ 200,000 | $ 200,000 |
OIL AND GAS PROPERTIES, BUILD_3
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and Natural Gas: | ||
Proved properties | $ 5,685,535 | $ 5,018,086 |
Unproved properties | 1,172,034 | 1,170,000 |
Facilities | 2,231,561 | 2,244,716 |
Oil and Natural Gas Total | 7,525,535 | 6,883,022 |
Less oil property impairment | (562,030) | |
Less accumulated depreciation, depletion, and amortization | (667,967) | (132,906) |
Oil and Natural Gas, Net | $ 6,869,697 | $ 6,188,086 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Current: | ||
Federal | ||
State | 4,000 | 2,000 |
Total | 4,000 | 2,000 |
Deferred: | ||
Federal | ||
State | ||
Total | ||
Total |
INCOME TAXES (Details 2)
INCOME TAXES (Details 2) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred income tax assets: | ||
Equity and deferred compensation | $ 255 | $ 239 |
Net operating loss | 2,442 | 1,918 |
State net operating loss carry forward | 1,020 | 808 |
Other, net | ||
Total deferred tax assets | 3,697 | 2,965 |
Valuation allowance | (3,211) | (2,907) |
Deferred Tax Assets, Net | 486 | 58 |
Deferred income tax liabilities: | ||
Depreciation and depletion | (486) | (58) |
Total deferred tax liabilities | ||
Net deferred income tax liabilities |
INCOME TAXES (Details Narrative
INCOME TAXES (Details Narrative) | Dec. 31, 2018USD ($) |
Income Tax Disclosure [Abstract] | |
Operating Loss Carryforwards, Fedral | $ 11,534,488 |
Operating Loss Carryforwards, State | $ 11,534,488 |
EQUIPMENT (Details)
EQUIPMENT (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Less: Accumulated depreciation | $ (44,758) | $ (22,364) |
Fixed assets, net | 67,326 | 82,969 |
Website [Member] | ||
Fixed Assets | 1,375 | 1,375 |
Furniture [Member] | ||
Fixed Assets | 20,380 | 20,380 |
Material/Pipe Supplies [Member] | ||
Fixed Assets | 6,750 | 0 |
Vehicles [Member] | ||
Fixed Assets | $ 83,578 | $ 83,578 |
EQUIPMENT (Details Narrative)
EQUIPMENT (Details Narrative) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | ||
Depreciation expense | $ 22,392 | $ 8,854 |
NOTES PAYABLE (Details Narrativ
NOTES PAYABLE (Details Narrative) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Notes Payable | ||
Note payable to an entity for the financing of insurance premiums, unsecured; 7.99% interest, due March 2019 | $ 13,939 | $ 14,548 |
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due October 2022 | 25,598 | 32,351 |
Note payable to an entity for the financing of a company vehicle, secured; 4.95% interest, due November 2022 | 26,390 | 33,052 |
Senior Secured Debt, 10% interest; due March 31, 2019 and March 31,2017 respectively | 2,350,000 | 500,000 |
Unamortized debt discount | (62,924) | |
Notes payable | $ 2,353,003 | $ 579,951 |
STOCK OPTION PLAN (Details)
STOCK OPTION PLAN (Details) - Stock Option [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Number of Options | ||
Outstanding, Beginning | 9,500,000 | 9,500,000 |
Granted | 500,000 | 9,500,000 |
Exercised | ||
Cancelled | ||
Outstanding, Ending | 10,000,000 | 9,500,000 |
Exercisable at end of period | 10,000,000 | |
Weighted-Average Exercise Price | ||
Outstanding, Beginning | $ 0.20 | $ 0.20 |
Granted | 0.20 | |
Exercised | 0 | |
Cancelled | 0 | |
Outstanding, Ending | $ 0.20 | 0.20 |
Exercisable at end of period | $ 0.20 | |
Weighted-Average Remaining Life (Years) | ||
Outstanding, Beginning | 3 years 3 months 4 days | 3 years 3 months 4 days |
Granted | 2 years 5 months 23 days | |
Outstanding, Ending | 2 years 5 months 23 days | 3 years 3 months 4 days |
Exercisable at end of period | 2 years 5 months 23 days | 3 years 3 months 4 days |
WARRANTS (Details)
WARRANTS (Details) - Warrant [Member] - $ / shares | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2018 | Sep. 30, 2017 | |
Number of Options | ||||||
Outstanding, Beginning | 1,125,000 | 875,000 | 875,000 | |||
Granted | 50,000 | 250,000 | 875,000 | |||
Exercised | ||||||
Cancelled | ||||||
Outstanding, Ending | 1,175,000 | 1,125,000 | 1,175,000 | 875,000 | ||
Exercisable at end of period | 875,000 | 1,125,000 | ||||
Weighted-Average Exercise Price | ||||||
Outstanding, Beginning | $ 0.20 | $ 0.20 | $ 0.20 | $ 0 | ||
Granted | 0.20 | 0.20 | ||||
Exercised | 0 | 0 | ||||
Cancelled | 0 | 0 | ||||
Outstanding, Ending | $ 0.20 | $ 0.20 | $ 0.20 | $ 0.20 | ||
Exercisable at end of period | $ 0.20 | $ 0.20 | ||||
Weighted-Average Remaining Life (Years) | ||||||
Granted | 4 years 9 months 14 days | 4 years 8 months 23 days | 4 years 2 months 16 days | |||
Outstanding at at end of period | 4 years 10 months 6 days | 4 years 3 months 25 days | 4 years 2 months 16 days | |||
Exercisable at at end of period | 4 years 3 months 25 days | 4 years 2 months 16 days |
SUPPLEMENTAL DISCLOSURE OF OI_3
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Oil and natural gas properties: | |||
Facilities | $ 2,231,561 | $ 2,244,716 | |
Oil and Natural Gas Properties [Member] | |||
Oil and natural gas properties: | |||
Proved properties | 4,513,000 | 3,513,000 | |
Unproved properties | 1,172,000 | 1,170,000 | |
Facilities | 2,415,000 | 2,200,000 | |
Total oil and natural gas properties | 8,100,000 | 6,883,000 | |
Less oil property impairment | (562,000) | (562,000) | |
Less accumulated depreciation, depletion and amortization | (668,000) | (133,000) | |
Net oil and natural gas properties capitalized | 6,870,000 | 6,188,000 | |
Acquisition costs: | |||
Proved properties | |||
Unproved properties | |||
Development costs | 2,211,000 | 344,000 | 2,171,000 |
Total | $ 2,211,000 | $ 344,000 | $ 2,171,000 |
SUPPLEMENTAL DISCLOSURE OF OI_4
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 2) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Supplemental Disclosure Of Oil And Natural Gas Operations Details 2 | ||||
Future cash inflows | $ 82,708,000 | $ 56,674,000 | $ 41,220,000 | |
Future development costs | (9,575,000) | (9,350,000) | (8,785,000) | |
Future production costs | (36,289,000) | (29,232,000) | (25,567,000) | |
Future income tax expenses | (5,476,000) | (1,521,000) | (860,000) | |
Future net cash flows | 31,368,000 | 16,571,000 | 6,008,000 | |
Ten percent discount to reflect timing of cash flows | (14,033,000) | (6,871,000) | (2,927,000) | |
Standardized measure of discounted future net cash flows | $ 17,335,000 | $ 9,700,000 | $ 3,081,000 | $ 7,107,000 |
SUPPLEMENTAL DISCLOSURE OF OI_5
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 3) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Disclosure Of Oil And Natural Gas Operations Details 3 | |||
Standardized measure of discounted future net cash flows at the beginning of the year | $ 9,700,000 | $ 3,081,000 | $ 7,107,000 |
Sales of oil and natural gas, net of production costs | (271,000) | (66,000) | (5,000) |
Purchase of minerals in place | |||
Previously estimated development costs incurred during the period | 1,559,000 | 334,000 | |
Net changes in prices and production costs | 8,839,000 | 4,826,000 | 8,927,000 |
Changes in estimated future development costs | (121,000) | (324,000) | 4,356,000 |
Revisions of previous quantity estimates | 13,290,000 | (1,896,000) | (21,886,000) |
Accretion of discount | 970,000 | 267,000 | 420,000 |
Net change in income taxes | (2,122,000) | (314,000) | 2,114,000 |
Net changes in timing of production and other | (2,548,000) | 2,048,000 | |
Standardized measure of discounted future net cash flows at the end of the year | $ 17,335,000 | $ 9,700,000 | $ 3,081,000 |