Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Mar. 31, 2017 | |
Document And Entity Information | ||
Entity Registrant Name | Citadel Exploration, Inc. | |
Entity Central Index Key | 1,482,075 | |
Document Type | 10-K | |
Document Period End Date | Dec. 31, 2016 | |
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 | Smaller Reporting Company | |
Entity Public Float | $ 9,042,220 | |
Entity Common Stock, Shares Outstanding | 41,348,002 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2,016 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash | $ 188,793 | $ 146,555 |
Other receivable | 7,142 | 19,342 |
Prepaid expenses | 33,436 | 29,870 |
Product inventory | 4,881 | 4,881 |
Total current assets | 234,252 | 200,648 |
Deposits | 9,900 | 9,900 |
Restricted cash | 245,000 | 245,000 |
Oil and gas properties, successful efforts basis | 6,209,546 | 4,173,307 |
Fixed asset, net | 18,530 | 13,860 |
Total assets | 6,717,228 | 4,642,715 |
Current liabilities: | ||
Accounts payable and accrued payables | 1,584,258 | 1,047,169 |
Accrued interest payable | 780,049 | 227,945 |
Notes payable, net | 526,880 | 525,034 |
Notes payable, related party, net | 3,500,000 | |
Preferred stock payable | 6,514,600 | |
Total current liabilities | 9,405,787 | 5,300,148 |
Asset retirement obligation | 217,212 | 198,279 |
Production payment liability | 300,000 | 300,000 |
Total liabilities | 9,922,999 | 5,798,427 |
Stockholders' equity: | ||
Common stock, $0.001 par value, 100,000,000 shares authorized, 39,314,000 and 38,814,000 shares issued and outstanding as of December 31, 2016 and December 31, 2015, respectively | 39,314 | 38,814 |
Additional paid-in capital | 5,790,060 | 5,690,560 |
Accumulated deficit | (9,035,145) | (6,885,086) |
Total stockholders' equity | (3,205,771) | (1,155,712) |
Total liabilities and stockholders' equity | $ 6,717,228 | $ 4,642,715 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
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 | 39,314,000 | 38,814,000 |
Common stock, outstanding | 39,314,000 | 38,814,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | ||
Revenue | $ 107,071 | $ 118,327 |
Operating expenses: | ||
Lease operating expense | 221,160 | 199,908 |
General and administrative | 9,985 | |
Geological and geophysical expense | 530,986 | 306,471 |
Depreciation, depletion and amortization | 23,284 | 20,226 |
Professional fees | 209,910 | 67,410 |
Executive compensation | 550,879 | 809,323 |
Dry hole, abandonment, impairment, and exploration | 140,606 | |
Total operating expenses | 1,676,826 | 1,413,323 |
Other expenses: | ||
Loss - contingency | (87,000) | |
Loss - note payable settlement | (26,080) | |
Interest expense | (572,025) | (220,413) |
Total other expenses | (572,025) | (333,413) |
Loss before provision for income taxes | (2,141,780) | (1,628,409) |
Provision for income taxes | (8,279) | |
Net loss | $ (2,150,059) | $ (1,628,409) |
Weighted average number of common shares - outstanding - basic and diluted | 39,042,142 | 34,937,077 |
Net loss per share - basic and diluted | $ (0.05) | $ (0.05) |
Consolidated Statements of Stoc
Consolidated Statements of Stockholder Deficit - USD ($) | Common Stock | Additional Paid-In Capital | Stock Payable | Accumulated Deficit | Total |
Beginning Balance at Dec. 31, 2014 | $ 31,389 | $ 4,673,497 | $ 2,250 | $ (5,256,677) | $ (549,541) |
Beginning Balance, Shares at Dec. 31, 2014 | 31,389,000 | ||||
Shares issued for cash | $ 719 | 107,117 | 107,836 | ||
Shares issued for cash, shares | 718,904 | ||||
Shares issued for property purchase | $ 6,000 | 474,000 | 480,000 | ||
Shares issued for property purchase, shares | 6,000,000 | ||||
Shares issued for settlement of notes payable | $ 681 | 101,483 | 102,164 | ||
Shares issued for settlement of notes payable, shares | 681,100 | ||||
Warrants issued with notes payable | 3,054 | 3,054 | |||
Stock option compensation | 302,189 | 302,189 | |||
Shares issued for share subscription settlement | $ 25 | 3,725 | (2,250) | 1,500 | |
Shares issued for share subscription settlement, shares | 25,000 | ||||
Shares issued to convert debt | 25,495 | 25,495 | |||
Net loss | (1,628,409) | (1,628,409) | |||
Ending Balance at Dec. 31, 2015 | $ 38,814 | 5,690,560 | (6,885,086) | (1,155,712) | |
Ending Balance, Shares at Dec. 31, 2015 | 38,814,004 | ||||
Shares issued for cash | $ 500 | 99,500 | 100,000 | ||
Shares issued for cash, shares | 500,000 | ||||
Net loss | (2,150,059) | (2,150,059) | |||
Ending Balance at Dec. 31, 2016 | $ 39,314 | $ 5,790,060 | $ (9,035,145) | $ (3,205,771) | |
Ending Balance, Shares at Dec. 31, 2016 | 39,314,004 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
OPERATING ACTIVITIES | ||
Net loss | $ (2,150,059) | $ (1,628,409) |
Adjustments to reconcile net loss to net cash used in operating activities: | ||
Depreciation, amortization and accretion | 23,284 | 20,226 |
Amortization of debt discount | 5,751 | 10,291 |
Gain - notes payable settlement | 26,080 | |
Executive stock based compensation expense | 302,188 | |
Changes in operating assets and liabilities: | ||
Increase/(Decrease) in other receivable | 12,200 | (18,133) |
Decrease in prepaid expenses | (3,566) | 6,016 |
Increase in deposits | (205,000) | |
Increase in accounts payable and accrued payables | 537,089 | 439,541 |
Increase in accrued interest payable | 545,354 | 227,945 |
Net cash used in operating activities | (1,028,947) | (819,253) |
INVESTING ACTIVITIES | ||
Oil and gas properties | (2,032,760) | (930,426) |
Property Acquisitions | (2,000,000) | |
Purchase of equipment | (12,500) | |
Net cash used in investing activities | (2,045,260) | (2,930,426) |
FINANCING ACTIVITIES | ||
Proceeds from sale of common stock, net of costs | 100,000 | 239,244 |
Proceeds from sale of preferred stock, net of costs | 3,014,600 | |
Proceeds from notes payable | 68,736 | 3,500,000 |
Repayments of notes payable | (66,891) | (113,308) |
Net cash provided by financing activities | 3,116,445 | 3,625,936 |
NET CHANGE IN CASH | 42,238 | (123,743) |
CASH AT BEGINNING OF YEAR | 146,555 | 270,298 |
CASH AT END OF YEAR | 188,793 | 146,555 |
SUPPLEMENTAL INFORMATION: | ||
Interest paid | 5,584 | (651) |
Income taxes paid | 8,279 | |
NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||
Financing of insurance | 68,736 | 62,548 |
Issuance of preferred stock for settlement of note payable - related party | 480,000 | |
Conversion of debt to equity | 3,500,000 | 25,495 |
Issuance of common stock for settlement of notes payable and accrued interest | 102,164 | |
Asset retirement obligation | $ 12,264 | $ 146,720 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 and 2015, 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, 2016 and 2015. 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 Effective, January 1, 2013, the Company changed its policy to account for its oil and natural gas exploration and development costs using the successful efforts method. The Company evaluated the impact on the prior periods and there were no material changes to the balance sheet as a result of the change in accounting policy. 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. This eliminates accounting for share-based compensation transactions using the intrinsic value and requires instead that such transactions be accounted for using a fair-value-based method. 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 718-10 and the conclusions reached by the 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 The Company has three bonds at financial institutions to meet financial bonding requirements in the state of California. As of December 31, 2016, restricted cash totaled $245,000. Debt discount The Company records debt discount as a contra liability account and is presented net of the associated note payable. The discount is amortized over the life on the note payable using the straight line method because the straight line method approximates the effective interest method. Revenue Recognition Revenues associated with sales of oil are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. 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 oil revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. 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, 2016 is $9,035,145 and the deferred tax asset is $3,689,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,689,000. 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, 2016 and 2015, 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, 2016 and 2015, 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. Recent pronouncements The Company has evaluated the recent accounting pronouncements through March 2017 and believes that none of them will have a material effect on the company’s consolidated financial statements. |
GOING CONCERN
GOING CONCERN | 12 Months Ended |
Dec. 31, 2016 | |
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 period ended December 31, 2016 of $2,150,059. In addition, the Company’s exploration activities since inception have been financially sustained through debt and equity financing. 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. |
PREPAID EXPENSES
PREPAID EXPENSES | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Prepaid Expenses | Note 3 –Prepaid Expenses As of December 31, 2016 and 2015, the Company had prepaid insurance totaling $33,436 and $29,870 respectively. The prepaid insurance will be expensed on a straight line basis over the remaining life of the insurance policies. During the years ended December 31, 2016 and 2015, the Company recorded $87,788 and $115,410 of insurance expenses. As of December 31, 2016 and 2015, the Company had a prepaid deposit of $5,000 and $5,000 respectively for leased office space. |
OIL AND GAS PROPERTIES, BUILDIN
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT | Note 4 – Oil and Gas Properties, Buildings, and Equipment Oil and natural gas properties, buildings and equipment consist of the following: 2016 2015 Oil and Natural Gas: Proved properties $ 3,751,401 $ 1,734,223 Unproved properties 1,170,000 2,444,608 Facilities 1,443,060 6,364,461 4,178,831 Less oil property impairment (140,606 ) — Less accumulated depreciation, depletion, and amortization (14,309 ) (5,524 ) $ 6,209,546 $ 4,173,307 Project Indian Project Indian is located in the Bitterwater sub-basin of the Salinas Basin, north of the giant San Ardo Field. Citadel currently owns a 100% working interest at Project Indian. In July of 2014 Citadel ended its prior joint venture with Sojitz Energy Ventures. There is a 20% royalty on the property owned by Vintage Petroleum, a wholly owned subsidiary of Occidental Petroleum Inc. In November of 2014 Occidental Petroleum Inc. spun off its California assets into a new public company called California Resources Corporation, which is listed on the New York Stock Exchange under the ticker CRC. CRC is now the mineral owner at Project Indian. In January of 2014, Citadel drilled and completed the first well at Project Indian, the Indian #1-15, and conducted a successful steam cycle in June of 2014. The Indian #1-15 then produced 3 to 7 barrels per day over several weeks before production halted because the well was shut-in by an order of the Superior Court of the State of California-County of Monterey entitled Center for Biological Diversity v. San Benito County Case no. M123956 (hereinafter the “Case”). In the Case, the Center for Biological Diversity, a non-governmental entity, petitioned the Court over the approval of Project Indian by the County of San Benito on a unanimous, 5-0 vote. Specifically, it argued that Project Indian required an Environmental Impact Report and not a Mitigated Negative Declaration which was the standard of environmental due diligence required by the County before its unanimous approval of the Project. The Court approved the petition in a judgment entered on September 4, 2014, and ruled that Citadel was required to obtain an environmental impact report before commencing further at Project Indian. Then, on November 4, 2014 Measure J was passed by a majority of participating, registered voters in the County of San Benito. Measure J bans hydraulic fracturing and other stimulation techniques defined as “high intensity petroleum operations” by the Measure, including cyclic steam injection. Citadel believes the passing of Measure J constitutes a regulatory taking of property and is preempted by the State of California. At this time there is no certainty that we will be able to develop Project Indian. Management has determined to shift capital resources to concentrate on drill ready projects that will immediately produce revenue. Consequently, the Company has suspended future capital expenditures related to Project Indian. Management impaired Project Indian in the fourth quarter of 2014 with a value of $1,420,574. The Company maintains its lease rights, takings claims, and no waiver of any right is intended by taking the foregoing impairment. Any action taken by the Company with respect to Project Indian in the near future, if any, will likely only be taken to preserve or advance the Company’s aforementioned legal rights and interests. Yowlumne In May 2013, we leased approximately 2,800 acres from AERA Energy, LLC (“Aera”). This acreage has been mapped using a combination of both 2D and 3D seismic, and is in close proximity to the Yowlumne oil field in Kern County, California. The Company is obligated to pay a 20% royalty to Aera. In August of 2013, the Company entered into an agreement to sell 55% of the interest in the Yowlumne lease, recouping approximately 85% of its cost, while retaining a 25% interest in the lease and operatorship. In July of 2014 the Company ended its joint venture with Sojitz Energy Ventures retaining Sojitz’s 55% interest in the Yowlumne lease, therefore increasing Citadel’s ownership to 75% in the Yowlumne lease. Additionally, as part of this transaction, the Company retained 100% interest in the Yowlumne #2-26 well, and the 160 acres surrounding the well bore. The Yowlumne #2-26 was first drilled in 2008 under supervision of Citadel CEO, Armen Nahabedian, during his previous tenure with his family’s oil company. Although the well tested oil at that time, the well was left idle for 5 years as lease issues prevented operations on the well until the appropriate curative measures could be taken. In December of 2014, Citadel began a work-over on the Yowlumne #2-26 well including installation of a new pump in February of 2015. The well has been producing approximately 20- 25 barrels per day (32 degree API quality) since the beginning of March. In June the well’s pump had a mechanical issue, the company performed well maintenance operations on the #2-26 well in August, which returned the well to production at approximately 20-25 barrels per day. Citadel anticipates returning the well to production in the second or third quarter of 2017. Citadel is in the final stages of the CEQA process to permit two additional exploration wells on the Yowlumne acreage. Recent regulatory changes, including SB4 the State of California’s bill on fracking have delayed the final approval of our CEQA application. As such we do not expect to have these prospects permitted until 2017, at which time we will determine when to drill. Both of these exploration wells will be targeting the Stephens Sands at a depth of 12,000 to 15,000 feet. Citadel currently has a 75% working interest in these exploration prospects and is the operator. 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 risk-free 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, 2016, the Company reduced the asset value by $140,606 as a result of low oil prices. Kern Bluff Oil Field The following table summarizes the consideration paid to the sellers and the amounts of the assets acquired and liabilities assumed in the Kern Bluff Acquisitions: Consideration paid to sellers: Cash consideration $ 2,000,000 Stock consideration 480,000 2,480,000 Recognized amounts of identifiable assets acquired and liabilities assumed: Proved developed and undeveloped properties 2,370,000 Other assets acquired 110,000 Asset retirement obligation 146,720 Other liabilities assumed — Total identifiable net assets $ 2,626,720 In July of 2015, Citadel purchased approximately 1,100 acres encompassing the Kern Bluff Oil Field for $2,000,000 in cash and 6,000,000 shares of its common stock valued at $480,000, based on price per share on date of sale. The seller also retained a royalty that varies on a lease by lease basis; Citadel has 100% working interest in the field with an 80% net revenue interest. This field was discovered in 1944 by Gulf Oil. Gulf drilled approximately 169 wells in the field in the 1970’s and 1980’s recovering twelve million barrels of oil, primarily from the Santa Margarita formation located at depths in the 900 to 1,100 foot range. Analogous fields in the area have achieved recovery levels in the 40-90% range. Citadel believes it can recover 20-40% of the remaining OOIP, through down spacing, horizontal development, cyclic steam injection and exploitation of shallower by passed zones. In December of 2015, Citadel shifted its CAPEX focus to remediation of the existing acquired facilities. At the time of purchase, the oil at Kern Bluff was being processed by temporary facilities installed by the previous owner. As production increased in September, it quickly became apparent that these facilities were not capable of processing the additional volumes of oil and water being produced. The existing permanent facilities were built in the 1970’s by Gulf Oil and require extensive remediation including new pipe, valves, flanges and tank repair. In order to facilitate the remediation, Citadel elected to shut down the eight producing wells in early January. Citadel completed facility remediation in July of 2016; the facilities are estimated to have production capability of 500 barrels per day of oil. Citadel returned existing wells to production and then drilled three new wells during the third quarter of 2016. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 5 – Income Taxes The (benefit) provision for income taxes from continuing operations consists of the following (in thousands): Year Ended December 31, 2016 2015 Current: Federal $ — $ — State 8 2 8 2 Deferred: Federal — — State — — — — Total $ 8 $ 2 The components of the net deferred income tax liabilities consist of the following: Year Ended December 31, 2016 2015 Deferred income tax assets: Equity and deferred compensation 272 174 Net operating loss 2,728 2,092 State net operating loss carry forward 689 485 Other, net — — Total deferred tax assets 3,689 2,752 Valuation allowance (3,628 ) (2,422 ) 61 330 Deferred income tax liabilities: Depreciation and depletion (61 ) (330 ) Net deferred income tax liabilities $ — $ — As of December 31, 2016, we had approximately $9,035,000 in net operating loss carryforwards for each federal and state income tax purposes. 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. 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, 2016 | |
Notes to Financial Statements | |
Equipment | Note 6 – Equipment Equipment as of December 31, 2016 and 2015 are as follows: 2016 2015 Vehicles $ 46,072 $ 33,572 Website 1,375 1,375 Furniture 10,000 10,000 Computer Equipment 8,165 8,165 Less: Accumulated depreciation (47,083 ) (39,252 ) $ 18,530 $ 13,860 Depreciation expense for the years ended December 31, 2016 and 2015 was $7,831 and $12,067. |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
NOTES PAYABLE | Note 7 – Notes Payable Notes payable consists of the following: December 31, 2016 December Note payable to an entity for the financing of insurance premiums, unsecured; 7.75% interest, due March 2017 $ 26,880 $ — Note payable to an entity for the financing of insurance premiums, unsecured; 7.44% interest, due March 2016 — 25,034 Two notes payable to investors, unsecured, 10% interest; due March 31, 2017 500,000 500,000 Notes Payable – Total $ 526,880 $ 525,034 Notes Payable, Related Party Term loan with a related party investor executed July 30, 2015, unsecured, 10% interest; due July 30, 2016 $ — $ 3,500,000 Total – Notes Payable & Notes Payable, Related Party $ 526,880 $ 4,025,034 Interest expense for the year ended December 31, 2016 was $572,025. Of that amount $566,273 relates to preferred stock, notes payable and insurance financing and $5,751 is amortization of debt discount. Interest expense for the year ended December 31, 2015 was $220,413. Of that amount $209,168 relates to notes payable and insurance financing and $10,291 is amortization of debt discount. |
PRODUCTION PAYMENT LIABIITY
PRODUCTION PAYMENT LIABIITY | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Production Payment Liability | Note 8 – 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, 2016 | |
Notes to Financial Statements | |
Asset Retirement Obligations (AROs) | Note 9 – 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, 2016 2015 Beginning balance at January 1 $ 198,279 $ 48,923 Liabilities incurred from property acquisition 12,264 146,720 Accretion expense 6,669 2,636 Ending balance at December 31 $ 217,212 $ 198,279 |
STOCKHOLDERS' EQUITY (DEFICIT)
STOCKHOLDERS' EQUITY (DEFICIT) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
STOCKHOLDERS' EQUITY (DEFICIT) | Note 10 – Stockholders’ Deficit The Company is authorized to issue 100,000,000 shares of its $0.001 par value common stock. In March of 2015, the Company approved the issuance of 1,400,000 common stock shares for the conversion of a $100,000 promissory note, plus accrued interest of $2,164 and an additional capital investment of $107,836, all at fair value of $0.15 per share. In March of 2015, the Company issued 25,000 shares of common stock to settle the stock payable of $2,250 recorded as of December 31, 2014. In July of 2015, the Company issued 6,000,000 shares of common stock at fair value and paid $1,900,000 in cash for the Kern Bluff Oil Field. The Company had paid a $100,000 deposit on the property in May of 2015, upon execution of a letter of intent (LOI) on the field. In March of 2016, the Company approved the sale of up to 250,000 shares of Series A Convertible Participating Preferred Stock. 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. 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. In December of 2016, the Company was notified by its transfer agent, that prior to issuing its Series A Preferred stock, the Company was required to file a 14c with the Securities and Exchange Commission to authorize the issuance of previously sold Series A Preferred Stock. This delay in issuance of Series A Preferred required the Company to classify the Series A Preferred as a liability until the Series A Preferred is issued, which is expected in the first quarter of 2017. This will also require the Company to restate prior periods of their form 10Q, in which Series A Preferred Shares were sold, but not issued deeming them a liability. |
STOCK OPTION PLAN
STOCK OPTION PLAN | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
STOCK OPTION PLAN | Note 11 – Stock Option Plan On July 29, 2015 as approved by the Board of Directors, the Company granted 4,700,000 stock options to three members of management and 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. The total fair value of these options at the date of grant was estimated to be $376,490 and was determined 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%. During the year ended December 31, 2015, $152,198 was recorded as a stock based compensation expense. The following is a summary of the status of all of the Company’s stock options as of December 31, 2016 and changes during the period ended on that date: Number Weighted-Average Aggregate Weighted-Average Outstanding at January 1, 2015 4,800,000 $ 0.26 $ — 5.65 Exercisable at January 1, 2015 3,200,000 $ 0.22 $ — 3.79 Granted 4,700,000 $ 0.15 $ — 6.58 Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2015 9,500,000 $ 0.20 $ — 5.26 Exercisable at December 31, 2015 7,902,000 $ 0.20 $ — 4.55 Granted $ 0.00 $ — Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2016 9,500,000 $ 0.20 $ — 5.26 Exercisable at December 31, 2016 7,902,000 $ 0.20 $ — 4.00 |
WARRANTS
WARRANTS | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
WARRANTS | Note 12 – Warrants In March 2014, the Company closed on a $500,000 180-day bridge loan with two investors. The loans bear interest of 10%. Additionally, the investors were granted a total of 500,000 stock warrants to purchase stock at $1.00 per share for a period of two years valued at $147,102. The total fair value of these warrant at the date of grant was determined using the Black-Scholes option pricing model with an expected life of 2 years, a risk free interest rate of 0.45%, a dividend yield of 0% and expected volatility of 333%. In September of 2014, the maturity date of this bridge loan was extended by 30 days; in return the exercise price of the warrant was reduced to $0.34 per share, with the original two year term remaining. Due to the change in the terms of the warrants, the Company recalculated the value of the warrants to be $85,325. Accordingly, the Company recognized a gain on the extinguishment of $73,573. In December of 2015, the maturity date of this bridge loan was extended until September 30, 2016, in return the exercise price of the warrant was reduced to $0.20 and the term of the warrants also extended to until September 30, 2016. At September 30, 2016, the maturity date was further extended to March 31, 2017. The exercise price of the warrant did not change during the extension to March 31, 2016. The following is a summary of the status of all of the Company’s stock warrants as of December 31, 2016 and changes during the period ended on that date: Number Weighted-Average Weighted-Average Outstanding at January 1, 2015 500,000 $ 0.34 1.33 Granted — $ 0.00 — Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at December 31, 2015 500,000 $ 0.20 0.75 Exercisable at December 31, 2015 500,000 $ 0.20 0.75 Granted — $ 0.00 — Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at December 31, 2016 500,000 $ 0.20 0.25 Exercisable at December 31, 2016 500,000 $ 0.20 0.25 |
FAIR VALUE MEASUREMENT
FAIR VALUE MEASUREMENT | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENT | Note 13 – Fair Value Measurement Liabilities Measured at Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy the Company's net derivative liabilities that were measured at fair value on a recurring basis as of December 31, 2016 and 2015: Total Level 1 Level 2 Level 3 Derivatives liability, net December 31, 2016 $ — $ — $ — $ — December 31, 2015 $ — $ — $ — $ — Changes in Level 3 Fair Value Measurements The table below includes a rollforward of amounts included in the Company's Balance Sheet (including the change in fair value) for financial instruments classified by the Company within Level 3 of the fair value hierarchy. When a determination is made to classify a financial instrument within Level 3 of the fair value hierarchy, the determination is based upon the significance of the unobservable factors to the overall fair value measurement. Level 3 financial instruments typically include, in addition to the unobservable or Level 3 components, observable components (that is, components that are actively quoted and can be validated to external sources). Year Ended December 31 2016 2015 Fair value liability (asset), beginning of period $ — $ 13,308 Transfer out of Level 3(1) $ — $ (13,308 ) Realized and unrealized (gain) loss included in earnings $ — $ — Unrealized loss included in derivative liability $ — $ — Settlements $ — $ — Fair value liability, end of period $ — $ — (1) During the first quarter of 2015, the derivative liability was converted into shares of stock and these instruments were transferred to level 1. The inputs used to value common stock are defined as unadjusted quoted prices in active markets for identical assets or liabilities. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2016 | |
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. In July of 2015, the Company entered into a $3,500,000 one year term loan with Cibolo Creek Partners for the purchase and development of the Kern Bluff Oil Field. Mr. Walesa is currently on the Board of Directors of Citadel and a member of Cibolo Creek Partners. On September 1, 2015, the Company entered into a three year employment agreement with its CEO. The annual salary for the first year is $240,000, then in the second year it increases to $300,000, and in the third year it increases to $360,000. Additionally, the officer received 1,500,000 stock options recorded at a fair value of $120,156. During the year ended December 31, 2015, the Company recorded executive compensation totaling $240,000. On September 1, 2015, the Company entered into a three year employment agreement with its CFO. The annual salary for the first year is $240,000, then in the second year it increases to $300,000, and in the third year it increases to $360,000. Additionally, the officer received 1,500,000 stock options recorded at a fair value of $120,156. During the year ended December 31, 2015, the Company recorded executive compensation totaling $240,000. During the year ended December 31, 2015 and December 31, 2016, the Company made the following purchases in the amount of $227,903 and 364,253, 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, 2016 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | Note 15 – Subsequent Events In February of 2017, we sold an additional 5,000 shares of Series A Preferred Stock to Cibolo Creek Partners for cash proceeds of $100,000. In February of 2017, the company filed a 14C with the SEC approving the issuance of 500,000 shares of Series A Preferred, 500,000 shares of Series B Preferred and 500,000 shares of Series C Preferred. Additionally the Company increased its total authorized common shares from 100,000,000 to 300,000,000. In March of 2017, we issued 335,365 shares of Series A Preferred Shares to investors that subscribed to the offering in 2016. In March of 2017, we issued 5,000 shares of Series A Preferred Shares to investors that subscribed to the offering in 2017. In March of 2017, we paid a special common stock dividend to holders of the Series A Preferred Stock as accrued interest during the offering period of the Series A Preferred. Series A Preferred investors received 2,034,002 shares valued at $0.20 per share equal to the conversion price of the Series A Preferred. |
SUPPLEMENTAL DISCLOSURE OF OIL
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 Oil and natural gas properties: (in thousands) Proved properties $ 3,751 $ 1,734 Unproved properties 1,170 2,445 Facilities 1,443 — Total oil and natural gas properties 6,364 4,179 Less oil property impairment (141 ) Less accumulated depreciation, depletion and amortization (14 ) (6 ) Net oil and natural gas properties capitalized $ 6,209 $ 4,173 Costs Incurred for Oil and Natural Gas Producing Activities Year Ended December 31, 2016 2015 2014 Acquisition costs: (in thousands) Proved properties $ — $ 1,200 $ — Unproved properties — 1,170 391 Development costs 2,171 944 611 Total $ 2,171 $ 3,314 $ 1,002 Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2016, 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, 2016 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, 2016 2015 2014 Oil (per Bbl) $ 35.53 $ 44.62 $ N/A 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, 2016, 2015, and 2014, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: 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 Year Ended December 31, 2015 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) P roved Developed and Undeveloped Reserv Beginning of the year — — — Extensions and discoveries — — — Revisions of previous estimates — — — Purchases of reserves in place 1,418 — 1,418 Divestures of reserves in place — — — Production (4 ) — (4 ) End of the year 1,414 — 1,414 Proved Developed Reserves: Beginning of the year — — — End of the year 358 — 358 Proved Undeveloped Reserves: Beginning of the year — — — End of the year 1,056 — 1,056 Year Ended December 31, 2014 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) P roved Developed and Undeveloped Reserv Beginning of the year — — — Extensions and discoveries — — — Revisions of previous estimates — — — Purchases of reserves in place — — — Divestures of reserves in place — — — Production — — — End of the year — — — Proved Developed Reserves: Beginning of the year — — — End of the year — — — Proved Undeveloped Reserves: Beginning of the year — — — End of the year — — — 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, 2016, 2015, and 2014 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, 2016 2015 2014 (in thousands) Future cash inflows $ 41,220 $ 63,111 $ — Future development costs (8,785 ) (13,141 ) — Future production costs (25,567 ) (34,494 ) — Future income tax expenses (860 ) (2,974 ) — Future net cash flows 6,008 12,502 — 10% discount to reflect timing of cash flows (2,927 ) (5,395 ) — Standardized measure of discounted future net cash flows $ 3,081 $ 7,107 $ — In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2016, 2015, and 2014, 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, 2016 2015 2014 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the year $ 7,107 $ — $ — Sales of oil and natural gas, net of production costs (5 ) — — Purchase of minerals in place — 7,107 — Divestiture of minerals in place — — — Extensions and discoveries, net of future development costs — — — Previously estimated development costs incurred during the period — — — Net changes in prices and production costs 8,927 — — Changes in estimated future development costs 4,356 — — Revisions of previous quantity estimates (21,886 ) — — Accretion of discount 2,468 — — Net change in income taxes 2,114 — — Net changes in timing of production and other — — — Standardized measure of discounted future net cash flows at the end of the year $ 3,081 $ 7,107 $ — |
SUMMARY OF SIGNIFICANT ACCOUN23
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 and 2015, 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, 2016 and 2015. 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 Effective, January 1, 2013, the Company changed its policy to account for its oil and natural gas exploration and development costs using the successful efforts method. The Company evaluated the impact on the prior periods and there were no material changes to the balance sheet as a result of the change in accounting policy. 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. This eliminates accounting for share-based compensation transactions using the intrinsic value and requires instead that such transactions be accounted for using a fair-value-based method. 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 718-10 and the conclusions reached by the 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 The Company has three bonds at financial institutions to meet financial bonding requirements in the state of California. As of December 31, 2016, restricted cash totaled $245,000. |
Debt discount | Debt discount The Company records debt discount as a contra liability account and is presented net of the associated note payable. The discount is amortized over the life on the note payable using the straight line method because the straight line method approximates the effective interest method. |
Revenue recognition | Revenue Recognition Revenues associated with sales of oil are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. |
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 oil revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. 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, 2016 is $9,035,145 and the deferred tax asset is $3,689,000. The Company maintains a full valuation allowance for the deferred tax asset of $3,689,000. 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, 2016 and 2015, 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, 2016 and 2015, 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. |
Recent pronouncements | Recent pronouncements The Company has evaluated the recent accounting pronouncements through March 2017 and believes that none of them will have a material effect on the company’s consolidated financial statements. |
OIL AND GAS PROPERTIES, BUILD24
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Extractive Industries [Abstract] | |
The costs capitalized in oil and gas properties | 2016 2015 Oil and Natural Gas: Proved properties $ 3,751,401 $ 1,734,223 Unproved properties 1,170,000 2,444,608 Facilities 1,443,060 6,364,461 4,178,831 Less oil property impairment (140,606 ) — Less accumulated depreciation, depletion, and amortization (14,309 ) (5,524 ) $ 6,209,546 $ 4,173,307 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of (benefit) provision for income taxes | Year Ended December 31, 2016 2015 Current: Federal $ — $ — State 8 2 8 2 Deferred: Federal — — State — — — — Total $ 8 $ 2 The components of the net deferred income tax liabilities consist of the following: Year Ended December 31, 2016 2015 Deferred income tax assets: Equity and deferred compensation 272 174 Net operating loss 2,728 2,092 State net operating loss carry forward 689 485 Other, net — — Total deferred tax assets 3,689 2,752 Valuation allowance (3,628 ) (2,422 ) 61 330 Deferred income tax liabilities: Depreciation and depletion (61 ) (330 ) Net deferred income tax liabilities $ — $ — |
EQUIPMENT (Tables)
EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Schedule of Equipment | 2016 2015 Vehicles $ 46,072 $ 33,572 Website 1,375 1,375 Furniture 10,000 10,000 Computer Equipment 8,165 8,165 Less: Accumulated depreciation (47,083 ) (39,252 ) $ 18,530 $ 13,860 |
NOTES PAYABLE (Tables)
NOTES PAYABLE (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Notes payable consists of the following at: | December 31, 2016 December Note payable to an entity for the financing of insurance premiums, unsecured; 7.75% interest, due March 2017 $ 26,880 $ — Note payable to an entity for the financing of insurance premiums, unsecured; 7.44% interest, due March 2016 — 25,034 Two notes payable to investors, unsecured, 10% interest; due March 31, 2017 500,000 500,000 Notes Payable – Total $ 526,880 $ 525,034 Notes Payable, Related Party Term loan with a related party investor executed July 30, 2015, unsecured, 10% interest; due July 30, 2016 $ — $ 3,500,000 Total – Notes Payable & Notes Payable, Related Party $ 526,880 $ 4,025,034 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Company announced its first oil production | Year Ended December 31, 2016 2015 Beginning balance at January 1 $ 198,279 $ 48,923 Liabilities incurred from property acquisition 12,264 146,720 Accretion expense 6,669 2,636 Ending balance at December 31 $ 217,212 $ 198,279 |
STOCK OPTION PLAN (Tables)
STOCK OPTION PLAN (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Summary of the status of all of the Company's stock options | Number Weighted-Average Aggregate Weighted-Average Outstanding at January 1, 2015 4,800,000 $ 0.26 $ — 5.65 Exercisable at January 1, 2015 3,200,000 $ 0.22 $ — 3.79 Granted 4,700,000 $ 0.15 $ — 6.58 Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2015 9,500,000 $ 0.20 $ — 5.26 Exercisable at December 31, 2015 7,902,000 $ 0.20 $ — 4.55 Granted $ 0.00 $ — Exercised — $ 0.00 $ — — Cancelled — $ 0.00 $ — — Outstanding at December 31, 2016 9,500,000 $ 0.20 $ — 5.26 Exercisable at December 31, 2016 7,902,000 $ 0.20 $ — 4.00 |
WARRANTS (Tables)
WARRANTS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Summary of the status of all of the Company's stock warrants | Number Weighted-Average Weighted-Average Outstanding at January 1, 2015 500,000 $ 0.34 1.33 Granted — $ 0.00 — Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at December 31, 2015 500,000 $ 0.20 0.75 Exercisable at December 31, 2015 500,000 $ 0.20 0.75 Granted — $ 0.00 — Exercised — $ 0.00 — Cancelled — $ 0.00 — Outstanding at December 31, 2016 500,000 $ 0.20 0.25 Exercisable at December 31, 2016 500,000 $ 0.20 0.25 |
FAIR VALUE MEASUREMENT (Tables)
FAIR VALUE MEASUREMENT (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value of Derivative Liabilities on a Recurring Basis | Year Ended December 31 2016 2015 Fair value liability (asset), beginning of period $ — $ 13,308 Transfer out of Level 3(1) $ — $ (13,308 ) Realized and unrealized (gain) loss included in earnings $ — $ — Unrealized loss included in derivative liability $ — $ — Settlements $ — $ — Fair value liability, end of period $ — $ — (1) During the first quarter of 2015, the derivative liability was converted into shares of stock and these instruments were transferred to level 1. The inputs used to value common stock are defined as unadjusted quoted prices in active markets for identical assets or liabilities. |
SUPPLEMENTAL DISCLOSURE OF OI32
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Schedule of Oil and Natural Gas Reserves that are Attributable | December 31, 2016 2015 Oil and natural gas properties: (in thousands) Proved properties $ 3,751 $ 1,734 Unproved properties 1,170 2,445 Facilities 1,443 — Total oil and natural gas properties 6,364 4,179 Less oil property impairment (141 ) Less accumulated depreciation, depletion and amortization (14 ) (6 ) Net oil and natural gas properties capitalized $ 6,209 $ 4,173 |
Schedule of Reserve Quantity Information | Year Ended December 31, 2016 2015 2014 Acquisition costs: (in thousands) Proved properties $ — $ 1,200 $ — Unproved properties — 1,170 391 Development costs 2,171 944 611 Total $ 2,171 $ 3,314 $ 1,002 |
Schedule of Proved Developed and Undeveloped Reserves | 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 Year Ended December 31, 2015 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) P roved Developed and Undeveloped Reserv Beginning of the year — — — Extensions and discoveries — — — Revisions of previous estimates — — — Purchases of reserves in place 1,418 — 1,418 Divestures of reserves in place — — — Production (4 ) — (4 ) End of the year 1,414 — 1,414 Proved Developed Reserves: Beginning of the year — — — End of the year 358 — 358 Proved Undeveloped Reserves: Beginning of the year — — — End of the year 1,056 — 1,056 Year Ended December 31, 2014 Crude Oil Natural Gas (Bbls) (Mcf) Boe (in thousands) P roved Developed and Undeveloped Reserv Beginning of the year — — — Extensions and discoveries — — — Revisions of previous estimates — — — Purchases of reserves in place — — — Divestures of reserves in place — — — Production — — — End of the year — — — Proved Developed Reserves: Beginning of the year — — — End of the year — — — Proved Undeveloped Reserves: Beginning of the year — — — End of the year — — — |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | December 31, 2016 2015 2014 (in thousands) Future cash inflows $ 41,220 $ 63,111 $ — Future development costs (8,785 ) (13,141 ) — Future production costs (25,567 ) (34,494 ) — Future income tax expenses (860 ) (2,974 ) — Future net cash flows 6,008 12,502 — 10% discount to reflect timing of cash flows (2,927 ) (5,395 ) — Standardized measure of discounted future net cash flows $ 3,081 $ 7,107 $ — |
OIL AND GAS PROPERTIES, BUILD33
OIL AND GAS PROPERTIES, BUILDINGS AND EQUIPMENT (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and Natural Gas: | ||
Proved properties | $ 3,751,401 | $ 1,734,223 |
Unproved properties | 1,170,000 | 2,444,608 |
Oil and Natural Gas Total | 1,443,060 | 4,178,831 |
Less oil property impairment | (140,606) | |
Less accumulated depreciation, depletion, and amortization | (14,309) | (5,524) |
Oil and Natural Gas, Net | $ 6,209,546 | $ 4,173,307 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Current: | ||
State | $ 8,000 | $ 2,000 |
Total | 8,000 | 2,000 |
Deferred: | ||
Total | $ 8,279 |
INCOME TAXES (Details 2)
INCOME TAXES (Details 2) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred income tax assets: | ||
Equity and deferred compensation | $ 272 | $ 174 |
Net operating loss | 2,728 | 2,092 |
State net operating loss carry forward | 689 | 485 |
Other, net | ||
Total deferred tax assets | 3,689 | 2,752 |
Valuation allowance | (3,628) | (2,422) |
Deferred Tax Assets, Net | 61 | 330 |
Deferred income tax liabilities: | ||
Depreciation and depletion | $ (61) | $ (330) |
INCOME TAXES (Details Narrative
INCOME TAXES (Details Narrative) | Dec. 31, 2016USD ($) |
Income Tax Disclosure [Abstract] | |
Operating Loss Carryforwards, Fedral | $ 9,035,000 |
Operating Loss Carryforwards, State | $ 9,035,000 |
EQUIPMENT (Details)
EQUIPMENT (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Less: Accumulated depreciation | $ (47,083) | $ (39,252) |
Fixed assets, net | 18,530 | 13,860 |
Vehicles [Member] | ||
Fixed Assets | 46,072 | 33,572 |
Website [Member] | ||
Fixed Assets | 1,375 | 1,375 |
Furniture [Member] | ||
Fixed Assets | 10,000 | 10,000 |
Computer Equipment [Member] | ||
Fixed Assets | $ 8,165 | $ 8,165 |
EQUIPMENT (Details Narrative)
EQUIPMENT (Details Narrative) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Notes to Financial Statements | ||
Depreciation expense | $ 7,831 | $ 12,067 |
NOTES PAYABLE (Details Narrativ
NOTES PAYABLE (Details Narrative) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Notes Payable Details Narrative | ||
Note payable to an entity for the financing of insurance premiums, unsecured; 7.75% interest, due April 2017 | $ 26,880 | |
Note payable to an entity for the financing of insurance premiums, unsecured; 7.44% interest, due March 2016 | 25,034 | |
Two notes payable to investors, unsecured, 10% interest; due September 30, 2016 | 500,000 | 500,000 |
Notes payable | 526,880 | 525,034 |
Notes payable, related party, net | 3,500,000 | |
Total - Notes Payable & Notes Payable, Related Party | $ 564,202 | $ 3,970,869 |
ASSET RETIREMENT OBLIGATION (De
ASSET RETIREMENT OBLIGATION (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation Details | ||
Beginning Balance | $ 198,279 | $ 48,923 |
Liabilities acquired from property acquisition | 12,264 | 146,720 |
Accretion expense | 6,669 | 2,636 |
Ending Balance | $ 51,559 | $ 198,279 |
STOCK OPTION PLAN (Details)
STOCK OPTION PLAN (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Number of Options | ||
Outstanding at January 1 | 9,500,000 | 4,800,000 |
Granted | 3,200,000 | |
Exercised | 7,902,000 | 4,700,000 |
Cancelled | ||
Outstanding at June 30 | 9,500,000 | 9,500,000 |
Exercisable at June 30 | 7,902,000 | |
Weighted-Average Exercise Price | ||
Outstanding at January 1 | $ 0.20 | $ 0.26 |
Granted | .00 | 0.15 |
Exercised | 0 | 0.22 |
Cancelled | 0 | |
Outstanding at June 30 | 0.20 | $ 0.20 |
Exercisable at June 30 | $ 0.20 | |
Weighted-Average Remaining Life (Years) | ||
Outstanding at January 1 | 5 years 3 months 3 days | 5 years 7 months 24 days |
Granted | 4 years 6 months 17 days | 3 years 9 months 14 days |
Exercised | 6 years 6 months 28 days | |
Outstanding at June 30 | 5 years 3 months 3 days | 5 years 3 months 3 days |
Exercisable at June 30 | 4 years |
WARRANTS (Details)
WARRANTS (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Number of Options | ||
Outstanding at January 1 | 9,500,000 | 4,800,000 |
Granted | 3,200,000 | |
Exercised | 7,902,000 | 4,700,000 |
Cancelled | ||
Outstanding at June 30 | 9,500,000 | 9,500,000 |
Exercisable at June 30 | 7,902,000 | |
Weighted-Average Exercise Price | ||
Outstanding at January 1 | $ 0.20 | $ 0.26 |
Granted | .00 | 0.15 |
Exercised | 0 | 0.22 |
Cancelled | 0 | |
Outstanding at June 30 | 0.20 | $ 0.20 |
Exercisable at June 30 | $ 0.20 | |
Weighted-Average Remaining Life (Years) | ||
Outstanding at January 1 | 5 years 3 months 3 days | 5 years 7 months 24 days |
Granted | 4 years 6 months 17 days | 3 years 9 months 14 days |
Exercised | 6 years 6 months 28 days | |
Outstanding at June 30 | 5 years 3 months 3 days | 5 years 3 months 3 days |
Exercisable at June 30 | 4 years | |
Warrant [Member] | ||
Number of Options | ||
Outstanding at January 1 | 500,000 | 500,000 |
Granted | ||
Exercised | ||
Cancelled | ||
Outstanding at June 30 | 500,000 | 500,000 |
Exercisable at June 30 | 500,000 | |
Weighted-Average Exercise Price | ||
Outstanding at January 1 | $ 0.20 | $ 0.34 |
Granted | ||
Exercised | ||
Cancelled | 0 | |
Outstanding at June 30 | 0.20 | $ 0.20 |
Exercisable at June 30 | $ 0.20 | |
Weighted-Average Remaining Life (Years) | ||
Outstanding at January 1 | 9 months | 1 year 3 months 28 days |
Outstanding at June 30 | 3 months | 9 months |
Exercisable at June 30 | 3 months |
FAIR VALUE MEASUREMENT (Details
FAIR VALUE MEASUREMENT (Details) - Liabilities [Member] - Fair Value, Measurements, Recurring [Member] - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value of Liabilites | |||
Fair Value, Inputs, Level 3 [Member] | |||
Fair Value of Liabilites | $ 13,308 |
FAIR VALUE MEASUREMENT (Detai44
FAIR VALUE MEASUREMENT (Details 2) - Liabilities [Member] - Fair Value, Measurements, Recurring [Member] - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair value liability (asset), beginning of period | ||
Fair value liability, end of period | ||
Fair Value, Inputs, Level 3 [Member] | ||
Fair value liability (asset), beginning of period | 13,308 | |
Transfer out of Level 3 | (13,308) | |
Realized and unrealized (gain) loss included in earnings | ||
Unrealized loss included in derivative liability | ||
Settlements | ||
Fair value liability, end of period |
SUPPLEMENTAL DISCLOSURE OF OI45
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Oil and natural gas properties: | |||
Less oil property impairment | $ (140,606) | ||
Oil and Natural Gas Properties [Member] | |||
Oil and natural gas properties: | |||
Proved properties | 3,751,000 | $ 1,734,000 | |
Unproved properties | 1,170,000 | 2,445,000 | |
Facilities | 1,443,000 | ||
Total oil and natural gas properties | 6,364,000 | 4,179,000 | |
Less oil property impairment | (141,000) | ||
Less accumulated depreciation, depletion and amortization | (14,000) | (6,000) | |
Net oil and natural gas properties capitalized | 6,209,000 | 4,173,000 | |
Acquisition costs: | |||
Proved properties | 1,200,000 | ||
Unproved properties | 1,170,000 | $ 391,000 | |
Development costs | 2,171,000 | 944,000 | 611,000 |
Total | $ 2,171,000 | $ 3,314,000 | $ 1,002,000 |
SUPPLEMENTAL DISCLOSURE OF OI46
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 2) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Supplemental Disclosure Of Oil And Natural Gas Operations Details 2 | |||
Future cash inflows | $ 4,122,000 | $ 63,111,000 | |
Future development costs | (8,785,000) | (13,141,000) | |
Future production costs | (25,567,000) | (34,494,000) | |
Future income tax expenses | (860,000) | (2,974,000) | |
Future net cash flows | 6,008,000 | 12,502,000 | |
Ten percent discount to reflect timing of cash flows | (2,927,000) | (536,000) | |
Standardized measure of discounted future net cash flows | $ 3,081,000 | $ 7,107,000 | $ 0 |
SUPPLEMENTAL DISCLOSURE OF OI47
SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Details 3) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Disclosure Of Oil And Natural Gas Operations Details 3 | ||
Standardized measure of discounted future net cash flows at the beginning of the year | $ 7,107,000 | $ 0 |
Sales of oil and natural gas, net of production costs | (5,000) | |
Purchase of minerals in place | 7,107,000 | |
Net changes in prices and production costs | 8,927,000 | |
Changes in estimated future development costs | 4,356,000 | |
Revisions of previous quantity estimates | (21,886,000) | |
Accretion of discount | 2,468,000 | |
Net change in income taxes | 2,114,000 | |
Net changes in timing of production and other | ||
Standardized measure of discounted future net cash flows at the end of the year | $ 3,081,000 | $ 7,107,000 |